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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. __________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-005-3
(PROTECTION SYSTEM MAINTENANCE)
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Counsel
Brady A. Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
February 14, 2014
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II.
NOTICES AND COMMUNICATIONS ................................................................................ 3
III. BACKGROUND .................................................................................................................... 4
A.
Regulatory Framework ..................................................................................................... 4
B.
NERC Reliability Standards Development Procedure ..................................................... 5
C.
History of Project 2007-17.2 ............................................................................................ 6
IV. JUSTIFICATION FOR APPROVAL..................................................................................... 7
A.
Reclosing Relays .............................................................................................................. 9
B.
SAMS/SPCS Report......................................................................................................... 9
C.
Modifications in proposed Reliability Standard PRC-005-3 ......................................... 12
1.
Definitions .................................................................................................................. 12
2.
Applicability ............................................................................................................... 14
3.
Changes to Requirements in Reliability Standard PRC-005-2 ................................... 21
D.
E.
Implementation Plan ...................................................................................................... 22
1.
Retirement of Legacy Reliability Standards ............................................................... 23
2.
Compliance Timeframes for Each Requirement ........................................................ 24
3.
Newly Identified Automatic Reclosing Components ................................................. 24
Evidence Retention Periods ........................................................................................... 25
F. Enforceability of proposed Reliability Standard PRC-005-3 ............................................ 26
V.
CONCLUSION ..................................................................................................................... 27
Exhibit A
Proposed Reliability Standard PRC-005-3
Exhibit B
Implementation Plan for PRC-005-3
Exhibit C
Order No. 672 Criteria for PRC-005-3
Exhibit D
NERC SAMS-SPCS Joint Autoreclosing Report
Exhibit E
Supplementary Reference and FAQ Document
Exhibit F
Table of Issues and Directives
i
TABLE OF CONTENTS
Exhibit G
Analysis of Violation Risk Factors and Violation Security Levels
Exhibit H
Summary of Development History and Complete Record of Development
Exhibit I
Protection System Maintenance and Testing Standard Drafting Team Roster for
Project 2007-17.2
ii
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. __________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD PRC-005-3
(PROTECTION SYSTEM MAINTENANCE)
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”)1 and Section 39.52 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”)3 hereby submits for Commission approval:
proposed Reliability Standard PRC-005-3 (Protection System Maintenance) (Exhibit A);
one new (Automatic Reclosing) and five revised definitions (Unresolved Maintenance
Issue, Segment, Component Type, Component, and Countable Event)4;
the implementation plan for proposed Reliability Standard PRC-005-3 (“Implementation
Plan”) (Exhibit B); and
the Violation Risk Factors (“VRFs”) and the revised Violation Severity Levels (“VSLs”)
for proposed PRC-005-3 (Exhibit A and Exhibit G).
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2014).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
These terms were approved as PRC-005 specific definitions along with the approval of Reliability Standard
PRC-005-2. See Protection System Maintenance Reliability Standard, Order No. 793, 145 FERC ¶ 61,253 (2013).
The definitions can be found in the posted PRC-005-2 Reliability Standard. Once approved, the revised versions of
the definitions will located in the posted version of proposed PRC-005-3.
2
1
NERC requests that the Commission approve the proposed Reliability Standard and find that it is
just, reasonable, not unduly discriminatory or preferential, and in the public interest. 5 NERC
also requests approval of the retirement of Reliability Standard PRC-005-26 as detailed in the
Implementation Plan.
As required by Section 39.5(a)7 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standard PRC-005-3, a summary of the
development history (Exhibit H), and a demonstration that the proposed Reliability Standard
meets the criteria identified by the Commission in Order No. 6728 (Exhibit C). Proposed
Reliability Standard PRC-005-3 was approved by the NERC Board of Trustees on November 7,
2013.
I.
EXECUTIVE SUMMARY
In Order No. 758, the Commission directed NERC to include maintenance and testing of
reclosing relays that can affect the Reliable Operation of the Bulk-Power System in Reliability
Standard PRC-005. Reclosing relays are applied to facilitate automatic restoration of system
components following a Protection System operation.9 In certain circumstances the misoperation
of reclosing relays can impact the reliability of the Bulk-Power System.
5
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available at http://www.nerc.com/files/Glossary_of_Terms.pdf
6
Reliability Standard PRC-005-2 was approved by the Commission on December 19, 2013. See Order No.
793, 145 FERC ¶ 61,253.
7
18 C.F.R. § 39.5(a) (2013).
8
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
9
As reclosing relays facilitate automatic restoration, they are often referred to as “automatic reclosing
relays” or “autoreclosing relays”. The term “reclosing relay”, as used in this Petition, has the same meaning as the
terms “automatic reclosing relay” and “autoreclosing relay” as they may appear in Exhibits to this Petition.
2
In response to Order No. 758, the NERC System Analysis and Modeling Subcommittee
(“SAMS”) and System Protection and Control Subcommittee (“SPCS”) jointly performed a
technical study to determine which reclosing relays should be addressed within PRC-005 and
provide advice to the Protection System Maintenance and Testing Standard Drafting Team
(“Standard Drafting Team”) regarding appropriate maintenance intervals and activities for those
relays (“SAMS/SPCS Report”) (Exhibit D). The Standard Drafting Team developed revisions
to Reliability Standard PRC-005-2 in line with the SAMS/SPCS Report recommendations. As a
result, proposed Reliability Standard PRC-005-3 adds reclosing relays that can affect the reliable
operation of the Bulk-Power System to the applicability of Reliability Standard PRC-005 to
satisfy NERC’s commitment to address the Order No. 758 directive and provide for the
maintenance and testing of these relays.
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:10
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2013), to allow the inclusion
of more than two persons on the service list in this proceeding.
10
3
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
William H. Edwards*
Counsel
Brady A. Walker*
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
III.
Mark G. Lauby*
Vice President and Director of Standards
Valerie Agnew*
Director of Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
[email protected]
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005,11 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1)12
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
States will be subject to Commission-approved Reliability Standards. Section 215(d)(5)13 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a)14 of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
11
12
13
14
16 U.S.C. § 824o (2012).
Id. § 824(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
4
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should be made effective.
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA15 and Section 39.5(c)16 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
B.
NERC Reliability Standards Development Procedure
The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.17 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual.18 In its
order certifying NERC as the Commission’s Electric Reliability Organization, , the Commission
found that NERC’s proposed rules provide for reasonable notice and opportunity for public
comment, due process, openness, and a balance of interests in developing Reliability Standards19
15
16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).
17
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
whether a proposed Reliability Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-approved Reliability Standard development process for the
development of the particular proposed Reliability Standard in a proper manner, especially whether the process was
open and fair. However, we caution that we will not be sympathetic to arguments by interested parties that choose,
for whatever reason, not to participate in the ERO’s Reliability Standard development process if it is conducted in
good faith in accordance with the procedures approved by FERC.”).
18
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
19
116 FERC ¶ 61,062 at P 250.
16
5
and thus satisfies certain of the criteria for approving Reliability Standards.20 The development
process is open to any person or entity with a legitimate interest in the reliability of the BulkPower System. NERC considers the comments of all stakeholders, and a vote of stakeholders
and the NERC Board of Trustees is required to approve a Reliability Standard before the
Reliability Standard is submitted to the Commission for approval.
C.
History of Project 2007-17.2
In Order No. 693,21 the Commission approved Reliability Standard PRC-005-1 and
directed NERC to “develop a modification … through the Reliability Standards development
process that includes a requirement that maintenance and testing of a protection system must be
carried out within a maximum allowable interval that is appropriate to the type of the protection
system and its impact on the reliability of the Bulk-Power System.”22 In 2007, NERC initiated
Project 2007-17 Protection System Maintenance and Testing to address the Commission’s
directive.
While the Standard Drafting Team developed these revisions to PRC-005, the
Commission approved two interpretations of PRC-005-1. On April 15, 2011, NERC filed a
petition seeking Commission approval of an interpretation of Requirements R1 and R3 of
Reliability Standard PRC-004-1 (Analysis and Mitigation of Transmission and Generation
Protection System Misoperations) and Requirements R1 and R2 of Reliability Standard PRC005-1 (Transmission and Generation Protection System Maintenance and Testing). The
Commission approved NERC’s interpretation, effective as of September 26, 2011.23 On
20
Order No. 672 at PP 268, 270.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242
(“Order No. 693”), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
22
Id. at P 1475.
23
N. Am. Elec. Reliability Corp., 136 FERC 61,208 (2011).
21
6
February 3, 2012, the Commission issued Order No. 758,24 approving a second interpretation of
PRC-005-1. In that Order, the Commission directed NERC to address concerns raised regarding
reclosing relays in the revisions to Reliability Standard PRC-005-1. Specifically, the
Commission directed NERC to include maintenance and testing of reclosing relays that can
affect the reliable operation of the Bulk-Power System.25
In response to Order No. 758, the Standard Drafting Team drafted a Standard
Authorization Request to modify PRC-005 to include the maintenance and testing of reclosing
relays that can affect the Reliable Operation of the Bulk-Power System. On May 10, 2012, the
NERC Standards Committee accepted the Standard Authorization Request and authorized that it
be posted for information only along with the third draft of PRC-005-2.
On July 30, 2012, NERC submitted an informational filing26 reporting to the Commission
that proposed Reliability Standard PRC-005-2—containing the revisions to Reliability Standard
PRC-005-1 outlined in Order No. 693—was in the final stages of development and that NERC
would address the Commission’s directive regarding reclosing relays in a separate petition. On
January 17, 2013, the NERC Standards Committee approved a Standard Authorization Request
to address the addition of reclosing relays through Project 2007-17.2 Protection System
Maintenance and Testing - Phase 2 (Reclosing Relays).
IV.
JUSTIFICATION FOR APPROVAL
As discussed in Exhibit C and below, proposed Reliability Standard PRC-005-3 satisfies
the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
Interpretation of Protection System Reliability Standard, Order No. 758, 138 FERC ¶ 61,094 (“Order No.
758”), order on reh’g, 139 FERC ¶ 61,227 (2012).
25
Id. at P 22-27.
26
NERC Jul. 30, 2012 Informational Filing in Compliance with Order No. 758, Docket No. RM10-5 (2012),
available at:
http://www.nerc.com/pa/Stand/Project%202007172%20Protection%20System%20Manintenance%20and/Final_Info
_Filing_Order_758_07-30-12_complete.pdf.
24
7
preferential, and in the public interest. The improved proposed Reliability Standard promotes
reliability by adding Automatic Reclosing to the Commission-approved Reliability Standard
PRC-005-2. The purpose of proposed PRC-005-3 is to document and implement programs for
the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of
the Bulk Electric System so that they are kept in working order.
PRC-005-3 has five Requirements that address the inclusion of Automatic Reclosing.
The revised Reliability Standard requires entities to develop an appropriate Protection System
Maintenance Program, to implement their program, and to initiate the follow-up activities
necessary to resolve maintenance issues in the event they are unable to restore Automatic
Reclosing Components to proper working order while performing maintenance. Proposed PRC005-3 adds detailed tables of minimum maintenance activities and maximum maintenance
intervals for Automatic Reclosing to the existing PRC-005-2 Reliability Standard, extending the
benefits of a strong maintenance program to these Components. The subset of Automatic
Reclosing applications included in proposed PRC-005-3 is based on the findings of the
SAMS/SPCS Report included as Exhibit D. To assist responsible entities in understanding the
addition of Automatic Reclosing to PRC-005, the Standard Drafting Team revised the
Supplementary Reference and FAQ document developed with PRC-005-2 and posted the
document concurrently with the proposed Reliability Standard during each posting. This revised
document will be posted with the proposed PRC-005-3 Reliability Standard following approval.
Proposed PRC-005-3 satisfies the Commission’s directive in Order No. 758 by including
the necessary reclosing relay applications with the potential to impact Reliable Operation of the
Bulk-Power System in the scope of Reliability Standard PRC-005. Provided below is a
summary of the recommendations from the SAMS/SPCS Report including discussion of
8
reclosing relays, an overview of the modifications to Reliability Standard PRC-005-2 necessary
to meet the Commission’s directive, and a discussion of the Implementation Plan.
A.
Reclosing Relays
Reclosing relays are utilized on transmission systems to restore transmission elements to
service following automatic circuit breaker tripping.27 There are several types of reclosing
relays, including electromechanical, solid state, and microprocessor-based, which may be applied
in a variety of scenarios.28 Most reclosing relays share three main functions: supervisory, timing,
and output.29 A relay failure is most likely to occur as part of one of these functions. Reclosing
relays are typically installed to lessen the burden on Transmission Operators of manually
restoring transmission lines.30 Relays of this type also provide improved capability in restoration
of overhead transmission lines. The degree to which such capability is improved depends on the
nature of the fault—permanent or temporary—and on Transmission Operator practices regarding
manual restoration.31
While more efficient restoration of transmission lines following temporary faults does
provide an inherent reliability benefit, certain applications of reclosing relays can result in
undesired relay operation or operation not consistent with relay design, leading to adverse
reliability impacts. Because certain applications of reclosing relays can have the potential to
impact the Bulk-Power System, it is beneficial to reliability that those relays be included under
the applicability of proposed Reliability Standard PRC-005-3.
B.
27
28
29
30
31
SAMS/SPCS Report
See SAMS/SPCS Report, Ex. D at 2.
Id. at 3.
Id. at 3-4.
Id.at 3.
Id.
9
The SAMS/SPCS Report recommended that the Standard Drafting Team modify
Reliability Standard PRC‐005-2 to: 1) explicitly address maintenance and testing of reclosing
relays applied as an integral part of a Special Protection System; and 2) include maintenance and
testing of reclosing relays at or in proximity to generating plants at which the total installed
capacity is greater than the capacity of the largest generating unit within the Balancing Authority
Area.32 For this second category, the SAMS/SPCS Report suggested to define “proximity” as
substations one bus away if the substation is within 10 miles of the plant. The SAMS/SPCS
Report also suggested including a provision to exclude reclosing relays “if the equipment owner
can demonstrate to the Transmission Planner that a close‐in three‐phase fault for twice the
normal clearing time (capturing a minimum trip‐close‐trip time delay) does not result in a total
loss of generation in the interconnection exceeding the largest unit within the Balancing
Authority Area where the autoreclosing is applied.”33 Finally, the SAMS/SPCS Report included
recommendations for minimum maintenance activities and maximum intervals based on
comparable activities and intervals included in Reliability Standard PRC‐005‐2.34
To reach these recommendations, SAMS and SPCS considered the Commission’s
concerns in Order No. 758 and summarized in the SAMS/SPCS Report that the Commission’s
concerns could be grouped into two categories: (1) situations in which reclosing relays fail to
operate when required to maintain Bulk-Power System reliability; and (2) situations in which
reclosing relays operate in a manner not consistent with design, adversely affecting reliability of
the Bulk-Power System. The SAMS/SPCS Report addresses these two categories of concern by
32
33
34
Id. at 10.
Id.
Id.
10
studying reclosing applications to improve Bulk-Power System performance and to aid in
restoration.
In assessing the first category, SAMS and SPCS noted that while successful operation of
reclosing relays will enhance reliability of the Bulk-Power System, reclosing into a permanent
power system fault may adversely impact reliability. Because the potential for permanent power
system faults exists for any application, it is not possible to depend on successful reclosing relay
operation as a sole means to guarantee reliability or satisfy the Requirements contained in
Reliability Standards. The same issues exist for single‐pole reclosing with regard to the potential
for reclosing into a permanent fault after all three poles are tripped. The exception is when
reclosing relays are included as an integral part of a Special Protection System (“SPS”). In these
applications, other functions of the SPS will operate to preserve reliability in the event that
reclosing is unsuccessful; thus, failure of any part of the SPS may adversely impact reliability of
the Bulk-Power System.
In assessing the second category, SAMS and SPCS note that reclosing relays are typically
installed to alleviate the burden on operators of manually restoring transmission lines. Reclosing
relays also provide improved availability of overhead transmission lines. The degree to which
availability is improved depends on the nature of the fault (permanent or temporary) and on
Transmission Operator practices for manually restoring lines. While faster restoration of
transmission lines following temporary faults does provide an inherent reliability benefit, it is
possible for undesired operation of the reclosing scheme, not consistent with its design, to
adversely impact Bulk-Power System reliability. Certain credible failure modes, including those
related to supervision, timing, and output, may lead to undesired reclosing relay operation which
could pose a reliability risk.
11
C.
Modifications in proposed Reliability Standard PRC-005-3
As discussed below, certain parts of Reliability Standard PRC-005-2 have been modified
in order to add the necessary reclosing relays to the PRC-005 Reliability Standard.
1.
Definitions
NERC developed one new and five revised definitions to accompany proposed PRC-0053.35 NERC proposes the following new definition to define the scope of what is included when
Automatic Reclosing is referenced within the proposed PRC-005-3 Reliability Standard:
Automatic Reclosing – Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
This definition is intended only for use within the proposed Reliability Standard and will not, at
this time, be listed in the NERC Glossary of Terms.36 The term will be included within the
posted Reliability Standard itself.37 This definition establishes that “Automatic Reclosing”
includes reclosing relays and the associated dc control circuitry and reflects the SAMS/SPCS
Report recommendation that PRC-005-3 should apply to both the reclosing relay and associated
control circuitry. The recommendation includes both Component Types since a failure in the
reclosing relay or the control circuitry may result in the same adverse reliability impact.
In addition, the previously-approved defined terms “Protection System Maintenance
Program”, “Component Type”, “Component”, and “Countable Event” were revised to add the
35
The definitions were posted in the draft PRC-005-3 Reliability Standard during the standards development
process and will be implemented concurrently with the proposed Reliability Standard.
36
NERC acknowledges the Commission’s statement in Order No. 793 that “NERC should not adopt
inconsistent definitions for the same term.” Order No. 793 at P 70. Although this term will be posted along with the
proposed Reliability Standard, NERC will not develop additional definitions of the same term approved for use in a
particular Reliability Standard. If a future standards development project seeks to broaden the applicability of a
standard-specific defined term, the defined term and where the term is posted (in the Reliability Standard or in the
NERC Glossary of Terms) would need to be revisited through the standards development process.
37
For clarity, NERC relocated the definitions specific to the PRC-005 Reliability Standard in part 6 of
Section A (Introduction) in the posted version of the proposed Reliability Standard.
12
necessary reference to “Automatic Reclosing” or the associated Table within the proposed
Reliability Standard to facilitate coverage of Automatic Reclosing Components within the
coverage of the PRC-005 Requirements. The revised definitions are as follows (changes have
been italicized for convenience):
Protection System Maintenance Program (PSMP) — An
ongoing program by which Protection System and Automatic
Reclosing Components are kept in working order and proper
operation of malfunctioning Components is restored. A
maintenance program for a specific Component includes one or
more of the following activities:
Verify — Determine that the Component is functioning
correctly.
Monitor — Observe the routine in-service operation of the
Component.
Test — Apply signals to a Component to observe functional
performance or output behavior, or to diagnose problems.
Inspect — Examine for signs of Component failure, reduced
performance or degradation.
Calibrate — Adjust the operating threshold or measurement
accuracy of a measuring element to meet the intended
performance requirement.
Component Type – Either any one of the five specific elements of
the Protection System definition or any one of the two specific
elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of
equipment included in a Protection System or in Automatic
Reclosing, including but not limited to a protective relay, reclosing
relay, or current sensing device. The designation of what
constitutes a control circuit Component is dependent upon how an
entity performs and tracks the testing of the control circuitry. Some
entities test their control circuits on a breaker basis whereas others
test their circuitry on a local zone of protection basis. Thus, entities
are allowed the latitude to designate their own definitions of
control circuit Components. Another example of where the entity
has some discretion on determining what constitutes a single
Component is the voltage and current sensing devices, where the
13
entity may choose either to designate a full three-phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or
replacement, any condition discovered during the maintenance
activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action or a Protection
System Misoperation attributed to hardware failure or calibration
failure. Misoperations due to product design errors, software
errors, relay settings different from specified settings, Protection
System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Lastly, two definitions contain capitalization changes to the previously-approved
definitions to correctly reference the defined term “Component.” The revised definitions read as
follows:
Unresolved Maintenance Issue – A deficiency identified during a
maintenance activity that causes the Component to not meet the
intended performance, cannot be corrected during the maintenance
interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a
particular model or type from a single manufacturer that typically
share other common elements. Consistent performance is expected
across the entire population of a Segment. A Segment must contain
at least sixty (60) individual Components.
2.
Applicability
Automatic Reclosing is addressed in PRC-005‐3 by explicitly addressing it outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in a new subsection 4.2.6 under the listing of covered “Facilities.” The PRC‐005‐3
Supplementary Reference and FAQ document includes examples to depict which Automatic
Reclosing applications are included in the scope of the proposed PRC-005-3 Reliability
Standard. The Applicability, as detailed below, was recommended by the NERC SAMS and
14
SPCS after a lengthy review of the use of reclosing within the Bulk Electric System. SAMS and
SPCS concluded that reclosing is largely implemented throughout the Bulk Electric System as an
operating convenience, and that reclosing mal‐performance affects Bulk Electric System
reliability only when the reclosing is part of a Special Protection System, or when premature
reclosing has the potential to cause generating unit or plant instability.38
a)
Section 4.2.6.1
4.2.6.1 Automatic Reclosing applied on the terminals of Elements
connected to the BES bus located at generating plant substations
where the total installed gross generating plant capacity is greater
than the gross capacity of the largest BES generating unit within
the Balancing Authority Area.
The SAMS/SPCS Report assessed Automatic Reclosing failure modes for potential
effects to Reliable Operation of the Bulk-Power System. The report identified that premature
reclosing has the potential to cause generating unit or plant instability, and noted the impact on
Reliable Operation when the loss of generating resources exceeds the largest unit39 within the
Balancing Authority Area in which the Automatic Reclosing is applied. In this context, the
NERC Reliability Standards require consideration of loss of the largest generating unit within a
Balancing Authority Area; therefore, generation loss would not impact reliability unless the
combined capacity loss exceeds the largest unit within the Balancing Authority Area. Including
maintenance and testing of reclosing relays in PRC-005 is, therefore, appropriate for applications
of Automatic Reclosing at generating plants with capacity exceeding the largest unit within the
Balancing Authority Area.
38
See Supplementary Reference and FAQ, Ex.E at 7 (citing SAMS/SPCS Report).
See Supplementary Reference and FAQ, Ex. E at 7. In this context the capacity of the largest unit is the
value reported to the Balance Authority for generating plant capacity for planning and modeling purposes. This can
be nameplate or other values based on generating plant limitations such as boiler or turbine ratings.
39
15
The applicability includes a reference the Bulk Electric System (referred to in the
applicability section as “BES”) in order to define the generating plant bus at which Automatic
Reclosing is subject to PRC-005-3. In this context, “BES” is used to describe the high-voltage
switchyard bus on the transmission system side of the generator step-up transformer. Similarly,
“BES” is used to modify the largest generating unit with the Balancing Authority Area.
Revisions to the “Bulk Electric System” definition are unlikely to affect present classification of
generating units and buses in the context of the largest generating unit in a Balancing Authority
Area or stations with capacity that exceed the largest unit within the Balancing Authority Area.
However, PRC-005-3 will be workable regardless of how the Bulk Electric System is defined. If
an element is a Bulk Electric System Element and is located at a generating plant substation, it is
included per Section 4.2.6.1, and the Requirements for Automatic Reclosing apply.40
b)
Section 4.2.6.2
4.2.6.2 Automatic Reclosing applied on the terminals of all BES
Elements at substations one bus away from generating plants
specified in Section 4.2.6.1 when the substation is less than 10
circuit-miles from the generating plant substation.
Reclosing at transmission substations may affect the stability of generating units and
generating plants when applied in proximity to a generating plant. Therefore, the Standard
Drafting Team included applicability for Automatic Reclosing at buses in proximity to
generating plants, in addition to Bulk Electric System buses at generating plants. The criteria
that define proximity, i.e., “one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant substation,” originated
from the SAMS/SPCS Report. The criteria are based on the collective experience of the
40
See Section 2.4.1 in the Supplementary Reference and FAQ document, Ex. E, for additional discussion.
16
subcommittee members performing transient stability studies. Their experience reveals that for
cases in which generating units exhibit an unstable response to a bus fault at the high-side of the
generator step-up transformer, the units exhibit a stable response if the fault location is on the
order of one mile from the bus. The difference in response is based on two factors. The first is
the additional impedance between the generators and the fault. The second is that when there are
additional sources of fault current in addition to the generator, the in-feed from the other sources
makes the apparent impedance41 to the fault greater, further reducing the acceleration of the
generating units during the fault. The SAMS and SPCS members applied a safety factor in
recommending the 10-mile threshold.
c)
Section 4.2.6.3
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS
specified in Section 4.2.4.
As noted in the SAMS/SPCS Report, Special Protection Systems may be applied to meet
system performance requirements in the NERC Reliability Standards or to increase the transfer
limit associated with an Interconnection Reliability Operating Limit. When reclosing is included
as an integral part of such a SPS, a failure of the reclosing function may adversely impact BulkPower System reliability.42 In such applications, it typically is essential to successfully restore
the power system to its pre-contingency state after a fault or disturbance (e.g., reclosing a
transmission line connected at a generating station after it is tripped to clear a fault). Since it is
possible that the fault or disturbance will be sustained and prevent restoration to the precontingency state, the SPS must take remedial action (e.g., initiating control system action or
41
Apparent impedance is a term that refers to the effective impedance when more than one source contributes
current through an element, resulting in an effective impedance greater than the actual impedance of the element.
42
See SAMS/SPCS Report, Ex. E at 3.
17
tripping resources to reduce power transfers) if it determines the reclosing was unsuccessful.
Unsuccessful reclosing may result from failure of the Automatic Reclosing or because of a
subsequent trip when the fault or disturbance is sustained. In these applications Reliable
Operation of the Bulk-Power System is dependent on proper operation of the SPS. This
dependence on proper operation of the SPS dictates that maintenance and testing requirements
apply to all parts of the SPS.
d)
Footnote 1 Exclusion
FN1 Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2
may be excluded if the equipment owner can demonstrate that a
close-in three-phase fault present for twice the normal clearing
time (capturing a minimum trip-close-trip time delay) does not
result in a total loss of gross generation in the Interconnection
exceeding the gross capacity of the largest BES generating unit
within the Balancing Authority Area where the Automatic
Reclosing is applied.
The applicability for Automatic Reclosing in PRC-005-3 is based on the SAMS and
SPCS assessment of failure modes of reclosing relays that could impact Reliable Operation of
the Bulk-Power System. During the SAMS/SPCS study, the SPCS identified the worst case
reclosing relay failure modes and SAMS assessed the reliability risk to the Bulk-Power System.
The worst case failure mode identified by SPCS is a failure that would lead to reclosing with no
time delay. SAMS identified that this failure mode presents a risk to Reliable Operation of the
Bulk-Power System when reclosing relays are used at or in proximity to generating stations,
because it could lead to generating unit instability. SAMS and SPCS concluded that
maintenance and testing of Automatic Reclosing should be required when the potential loss of
generating resources may exceed the gross capacity of the largest Bulk Electric System unit
within the Balancing Authority Area where the Automatic Reclosing is applied. Thus, the
applicability establishes a bright line to allow entities to assess which Automatic Reclosing is
18
subject to requirements in PRC-005-3. Further, SAMS and SPCS recognized that failure of
Automatic Reclosing may not affect reliability of the Bulk-Power System at all locations
identified in the applicability of PRC-005-3. Determining which, if any, locations identified in
the applicability do not pose a reliability risk would require case-by-case studies of the worstcase failure mode on which the applicability is based. Rather than including a requirement in
PRC-005-3 for entities to perform such analysis, the Standard Drafting Team included Footnote
1 to allow entities the option to instead rule out certain locations at which this risk is not present.
Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing addressed
in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that a close‐in
three‐phase fault present for twice the normal clearing time (capturing a minimum trip‐close‐trip
time delay) does not result in a total loss of gross generation in the Interconnection exceeding the
gross capacity of the largest Bulk Electric System unit within the Balancing Authority Area
where the Automatic Reclosing is applied. This benchmark reflects the worst-case failure mode
identified by SAMS and SPCS and, therefore, serves as a valid, technically-supported test for
ruling out certain facilities from the applicability of PRC-005-3. The test simulates a fault for
twice the normal clearing time because this is approximately the same as clearing the fault in
normal clearing time, reclosing into the fault with no time delay, and clearing the fault again in
normal clearing time.
e)
NERC Evaluation of 10-Mile Threshold
As noted above, proposed Reliability Standard PRC-005-3 requires maintenance and
testing of reclosing relays at generating stations, and at substations one bus away from a
generating station if the substation is within 10 miles of the generating station. Further, the
19
criteria are based on the collective experience of the SAMS and SPCS members and include a
safety factor in establishing the ten-mile threshold.
NERC staff has conducted an analysis to verify that the 10-mile threshold provides
adequate margin to ensure maintenance and testing of all reclosing relays where failure could
result in generating station instability. Testing was performed at the high-voltage switchyard for
50 generating stations. A sample of generating stations was used with high-side voltage ranging
from 115 kV to 765 kV. The sample included a wide range of generating unit types,
transmission line lengths, and switchyard configurations, and is therefore representative of
generating stations across North America. Three-phase faults were simulated on each line43
exiting each generating station. Faults were simulated for a duration that conservatively
represents two times the normal clearing time for a three-phase fault. This test is based on a
recommendation in the SAMS-SPCS Report to apply a close-in three-phase fault for twice the
normal clearing time (capturing a minimum trip-close-trip time delay). This test approximates
the response if a transmission line circuit breaker is reclosed into a fault without any time delay
due to a reclosing relay failure. The fault durations used in the study are 8 cycles at voltage
greater than 300 kV, 10 cycles for clearing times for voltage between 200 kV and 300 kV, and
12 cycles for voltage below 200 kV. Close-in faults were applied on each line on the line side of
the circuit breaker(s). In cases where the generating unit response was unstable, the fault was
reapplied at one-mile increments away from the bus until the generating unit response was
stable. Testing was performed on a total of 145 transmission lines at 50 generating stations. The
generating unit response was stable for 110 of the close-in faults. For the remaining 35 lines, the
43
When two or more parallel lines exit a generating station and terminate at the same remote station, a fault
was applied on only one line since the response would be essentially the same faults on each line.
20
generating response was stable for faults one mile from the generating station in 22 cases and
was stable for faults greater than five miles from the generating station in 10 cases.
The three remaining cases involve two generating stations. At one station, the two
transmission lines exiting the station are approximately 120 miles long. On one line, the
generating units were stable for a fault 11 miles from the generating station and on the other line
the generating units were unstable for faults anywhere on the line. At this generating station the
predominant factor in the generating unit instability is the post-fault system impedance with the
generating units remaining connected to one 120-mile line. The analysis was repeated at each
remote bus at the remote terminal of the two 120-mile lines. The generating units were stable for
close-in three phase faults on each line terminating at these remote buses. Since these remote
buses are more than 10 miles from the generating station, PRC-005-3 would not be applicable to
the reclosing relays and the analysis confirms there is not a reliability need to include these
relays.
At the second generating station, one of the lines exiting the station is approximately two
miles in length. The generating units were unstable for faults anywhere on this line. Proposed
Reliability Standard PRC-005-3 would be applicable to reclosing relays at the remote bus
because it is less than 10 miles from the generating station. In this case the generating units
remain stable for close-in faults on each of the lines terminating at the remote bus, confirming
that the criterion is conservative.
3.
Changes to Requirements in Reliability Standard PRC-005-2
The proposed Reliability Standard consists of five Requirements. The Requirements and
the associated Measures have been modified, as necessary, to add in the coverage of Automatic
Reclosing to the Requirement language.
21
Requirement R1 now requires that Transmission Owners, Generator Owners, and
Distribution Providers establish a Protection System Maintenance Program both for Protection
Systems and for Automatic Reclosing relays as defined in the proposed Reliability Standard,
and, as in Reliability Standard PRC-005-2, includes guidelines for the development of such a
program.
Requirement R3 now requires Transmission Owners, Generator Owners, and Distribution
Providers that utilize time-based maintenance programs to maintain Protection Systems and
certain automatic reclosing relays as defined within the proposed Reliability Standard.
Requirement R4 now requires Transmission Owners, Generator Owners, and Distribution
Providers that utilize performance-based maintenance programs to implement and follow a
PSMP for Protection Systems and for Automatic Reclosing relays as defined within the proposed
Reliability Standard.
Revisions to Requirements R2 and R5 were not necessary as each will apply in the same
fashion in proposed Reliability Standard PRC-005-3 as approved by the Commission in
Reliability Standard PRC-005-2.
D.
Implementation Plan
The Implementation Plan for proposed Reliability Standard PRC-005-3 addresses both
Protection Systems and Automatic Reclosing. PRC-005-2 has recently been approved by the
Commission and has a twelve-year phased-in implementation period. The compliance dates for
the various Requirements with respect to maintenance of Protection System Components in
PRC-005-2 key off of the date of approval by the applicable regulatory authority. To account for
this timing, and in order not to lose time on maintenance activities completed prior to the
approval of PRC-005-3, the Standard Drafting Team has carried forward the language in the
22
implementation plan for PRC-005-2 and modified it to add compliance dates for the
Requirements with respect to Automatic Reclosing Components. The Standard Drafting Team
also modified the language for the compliance dates for Requirements with respect to Protection
System Components to explicitly reference that the compliance timing for these Components
counts forward from the applicable regulatory authority approval date for PRC-005-2. As a
result, the Implementation Plan for PRC-005-3 captures the necessary implementation
information for PRC-005-2. Under the Implementation Plan for PRC-005-3, entities will now, as
an initial matter, indicate whether their Component is being maintained under one of the legacy
Reliability Standards (PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0) or whether the
Component is being maintained pursuant to PRC-005-3. Because PRC-005-3 has carried the
Requirements from PRC-005-2 forward, including language regarding implementation timing,
there is no need for an entity to cite to the version 2 Reliability Standard during the phased-in
implementation period once the proposed Reliability Standard is approved.44 Additional aspects
of the Implementation Plan are addressed below.
1.
Retirement of Legacy Reliability Standards
The Implementation Plan continues to reflect that the retirement of the legacy Reliability
Standards will continue to key off of the applicable regulatory approval date of PRC-005-2.
Because Automatic Reclosing is a new Component covered by the PRC-005 Reliability
Standard, the retirement of the legacy Reliability Standards does not need to correspond with the
enforcement date of proposed PRC-005-3. Proposed PRC-005-3 will retire Reliability Standard
PRC-005-2 in the United States “at midnight of the day immediately prior to the first day of the
44
The same approach will be used with respect to the addition of sudden pressure relays. This will allow for
the full retirement of PRC-005-3 and its implementation plan leaving only one version of a new PRC-005 standard
as the enforceable Reliability Standard rather than needing to reference versions 2 through 4 for the next twelve
years.
23
first calendar quarter, twelve (12) calendar months following applicable regulatory approval of
PRC-005-3.”
2.
Compliance Timeframes for Each Requirement
The Implementation Plan includes identical timeframes for entities to become compliant
with the Requirements in PRC-005-3 as exist in the implementation plan for PRC-005-2. The
only difference is the date from which entities will count forward to determine the date the entity
must be compliant for a particular Component Type. Entities will continue to calculate
compliance dates for Requirements in connection with any Protection System Components by
counting forward from the applicable regulatory approval date of PRC-005-2. Entities will
continue to calculate compliance dates for Requirements in connection with any Automatic
Reclosing Components by counting forward from the applicable regulatory approval date of
PRC-005-3.
3.
Newly Identified Automatic Reclosing Components
The Implementation Plan also includes implementation timeframes for newly identified
Automatic Reclosing Components due to generation changes in the Balancing Authority Area.
Additional applicable Automatic Reclosing Components may be identified because of the
addition or retirement of generating units; or increases of gross generation capacity of individual
generating units or plants within the Balancing Authority Area. The Implementation Plan
provides that “ [i]n such cases, the responsible entities must complete the maintenance activities,
described in Table 4, for the newly identified Automatic Reclosing Components prior to the end
of the third calendar year following the identification of those Components unless documented
prior maintenance fulfilling the requirements of Table 4 is available.”
24
E.
Evidence Retention Periods
In order to establish effective maintenance procedures to ensure Reliable Operation of
the Bulk-Power System, the Standard Drafting Team established certain evidence retention
periods, which were approved by the Commission with Reliability Standard PRC-005-2. Those
same evidence retention periods are maintained in proposed Reliability Standard PRC-005-3.
These periods will now apply to evidence retained for compliance with the Requirements in
connection with Automatic Reclosing. Proposed PRC-005-3 continues to require entities to
maintain documentation for the longer of: (1) the two most recent performances of each distinct
maintenance activity for the Protection System or Automatic Reclosing Component; (2) all
performances of each distinct maintenance activity for the Protection System or Automatic
Reclosing Component since the previous scheduled audit date. The Standard Drafting Team
explains that this requirement assures that documentation is available to show that the time
between maintenance cycles correctly meets the maintenance interval limits.45 Maintaining
elements according to these intervals is a critical aspect of properly maintaining a covered
Component. Because some maintenance intervals in proposed PRC-005-3 (and the predecessor
Reliability Standard PRC-005-2) are up to twelve years, it is possible that an entity may need to
retain records for up to twenty-four years.
The evidence retention periods in proposed Reliability Standard PRC-005-346 continue to
be reasonable for this type of activity. The type of evidence entities will retain to demonstrate
that maintenance was last completed within a given interval are the usual and customary
documents maintained by these entities today to document maintenance internally of various
45
See Supplementary and FAQ, Ex. E at 39.
The evidence retention periods are outlined in the Compliance section of proposed Reliability Standard
PRC-005-3, attached hereto as Exhibit A. The written description of the evidence retention periods corresponds to
the Maintenance Interval and Maintenance Activities section of Table 1, also found in Exhibit A.
46
25
components. While the time intervals may seem longer than an entity may reasonably retain
such records, the lengthy periods are necessary to establish maintenance has occurred according
to the mandated intervals. Retaining records for the two most recent performances of each
distinct maintenance activity, where the interval is twelve years, is how the twenty-four year
retention period arises. Shortening the time period for retention would require that the
maintenance intervals be reduced as well, which would significantly increase capital
maintenance costs since entities would need to maintain Components under tighter time
constraints.
The Measures in the proposed Reliability Standard provide examples of acceptable types
of evidence for each Requirement, but the Measures do not mandate specific records be kept.
Therefore, entities will have the flexibility to determine the level of documentation needed to
verify this limited element of the proposed Reliability Standard. Generally, entities will likely
only maintain summaries of their maintenance activities pertaining to the prior period in order to
establish that the proper intervals were met. Therefore, the burden will be minimal compared to
the increased capital costs that would result from shortening the intervals to create a shorter
maximum retention time.
Recognizing that the period is long, NERC has requested that the Standard Drafting
Team consider possible alternatives or refinements to the evidence retention periods in the PRC005 Reliability Standard for all covered Component Types as part of NERC Project 2007-17.3 –
Protection System Maintenance and Testing (Sudden Pressure Relays).
F.
Enforceability of proposed Reliability Standard PRC-005-3
The proposed Reliability Standard includes Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”). The VRFs and VSLs for the proposed Reliability Standard
26
comport with NERC and Commission guidelines related to their assignment. For a detailed
review of the VRFs, the VSLs, and the analysis of how the VRFs and VSLs were determined
using these guidelines, please see Exhibit G.
Because the Requirements contained in proposed Reliability Standard PRC-005-3 track
with those contained in the already approved Reliability Standard PRC-005-2, the Standard
Drafting Team determined that no revisions were necessary to the VRFs for the proposed
Reliability Standard. NERC, therefore, requests that the Commission approve the VRFs as
applied to the Automatic Reclosing Components now included in the proposed Reliability
Standard.
The VSLs in PRC-005-2 have been revised accordingly to add the additional Component
into the levels of severity. The changes are consistent with the approach taken for the VSLs in
Reliability Standard PRC-005-2. The VSLs provide guidance on the way that NERC will
enforce the Requirements of the proposed Reliability Standard for each of the Component Types.
The proposed Reliability Standard also include Measures that support each Requirement
to help ensure that the Requirements will be enforced in a clear, consistent, and non-preferential
manner and without prejudice to any party.
V.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:
•
•
approve the proposed Reliability Standard and other associated elements included in Exhibit
A;
the new and revised definitions, as noted herein;
•
the VRFs and VSLs (as explained in Exhibit E);
•
approve the Implementation Plan included in Exhibit B; and
•
approve the retirement of Reliability Standard PRC-005-2, as proposed in the
Implementation Plan.
27
Respectfully submitted,
/s/ William H. Edwards
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
William H. Edwards
Counsel
Brady A. Walker
Associate Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: February 14, 2014
28
Exhibit A
Proposed Reliability Standard
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
6.
Definitions Used in this Standard: The following terms are defined for use only within
PRC-005-3, and should remain with the standard upon approval rather than being moved to the
Glossary of Terms.
Automatic Reclosing – Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty
(60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to
designate their own definitions of control circuit Components. Another example of where the
entity has some discretion on determining what constitutes a single Component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 41 through 4-2 which requires corrective action or a Protection System Misoperation attributed
to hardware failure or calibration failure. Misoperations due to product design errors, software
errors, relay settings different from specified settings, Protection System Component or
Automatic Reclosing configuration or application errors are not included in Countable Events.
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System shall be included in a time-based
program as described in Table 1-4 and Table 3.
1.2. Include the applicable monitored Component attributes applied to each Protection System
and Automatic Reclosing Component Type consistent with the maintenance intervals
specified in Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2 where
monitoring is used to extend the maintenance intervals beyond those specified for
unmonitored Protection System and Automatic Reclosing Components.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
Component Type in accordance
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
their performance-based PSMP.
with their performance-based
PSMP.
their performance-based PSMP.
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
October 17,
2013
Errata Change: The Standards Committee
approved an errata change to the
implementation plan for PRC-005-2 to add
the phrase “or as otherwise made effective
pursuant to the laws applicable to such ERO
governmental authorities;” to the second
sentence under the “Retirement of Existing
November 7,
2013
Adopted by the NERC Board of Trustees
2
3
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to address the
FERC directive in Order
No.758 to include
Automatic Reclosing in
maintenance programs.
10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
6 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Verify that the dc supply can perform as manufactured when ac power is
not present.
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Unmonitored control circuitry associated with SPS.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
No periodic
maintenance
specified
None.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Test and, if necessary calibrate.
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Alarming for power supply failure (See Table 2).
12 Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of Components included in each designated Segment,
with a minimum Segment population of 60 Components.
2. Maintain the Components in each Segment according to the time-based maximum
allowable intervals established in Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 until results of maintenance activities for the Segment are available for a
minimum of 30 individual Components of the Segment.
3. Document the maintenance program activities and results for each Segment, including
maintenance dates and Countable Events for each included Component.
4. Analyze the maintenance program activities and results for each Segment to determine
the overall performance of the Segment and develop maintenance intervals.
5. Determine the maximum allowable maintenance interval for each Segment such that the
Segment experiences Countable Events on no more than 4% of the Components within
the Segment, for the greater of either the last 30 Components maintained or all
Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
30
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-23
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that these Protection Systemsthey are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
1
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
6.
Definitions Used in this Standard: The following terms are defined for use only within
PRC-005-3, and should remain with the standard upon approval rather than being moved to the
Glossary of Terms.
Automatic Reclosing – Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty
(60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to
designate their own definitions of control circuit Components. Another example of where the
entity has some discretion on determining what constitutes a single Component is the voltage
and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 41 through 4-2 which requires corrective action or a Protection System Misoperation attributed
to hardware failure or calibration failure. Misoperations due to product design errors, software
errors, relay settings different from specified settings, Protection System Component or
Automatic Reclosing configuration or application errors are not included in Countable Events.
2
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
B. Requirements
R1. Each Transmission Owner, Generator Owner, and
Distribution Provider shall establish a Protection System
Maintenance Program (PSMP) for its Protection Systems
and Automatic Reclosing identified in Facilities Section
4.2. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method
(time-based, performance-based per
PRC-005 Attachment A, or a
combination) is used to address each
Protection System and Automatic
Reclosing Component Type. All batteries
associated with the station dc supply
Component Type of a Protection System
shall be included in a time-based
program as described in Table 1-4 and
Table 3.
1.2. Include the applicable monitored
Component Type - Any one of
the five specific elements of the
Protection System definition.
Component – A component is any individual
discrete piece of equipment included in a
Protection System, including but not limited to
a protective relay or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
Component attributes applied to each
Protection System and Automatic
Reclosing Component Type consistent
with the maintenance intervals specified
in Tables 1-1 through 1-5, Table 2, Table
3, and Table 34-1 through 4-2 where monitoring is used to extend the maintenance
intervals beyond those specified for unmonitored Protection System and Automatic
Reclosing Components.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 34-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
3
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Unresolved Maintenance Issue - A
deficiency identified during a
maintenance activity that causes the
component to not meet the intended
performance, cannot be corrected
during the maintenance interval, and
requires follow-up corrective action.
4
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each protectionProtection System and Automatic Reclosing
Component Type (such as manufacturer’s specifications or engineering drawings) of the
appropriate monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2,
Table 3, and Table 34-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
5
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
6
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3,
and Tables 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entityentity’s
PSMP failed to specify whether
threefour or more Component
Types are being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
7
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the
segmentSegment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3, and Tables 4-1
through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
total Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3, and Tables 41 through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the total Components included
within a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3, and Tables 4-1
through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 15% of the total
Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3, and Tables 41 through 4-2.
R4
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
8
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
5% or less of the annual scheduled
maintenance for a specific Protection
System Component Type in
accordance with their performancebased PSMP.
more than 5% but 10% or less of the
annual scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
more than 10% but 15% or less of
the annual scheduled maintenance
for a specific Protection System
Component Type in accordance with
their performance-based PSMP.
more than 15% of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
9
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July
2012March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
10
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
October 17,
2013
Errata Change: The Standards Committee
approved an errata change to the
implementation plan for PRC-005-2 to add
the phrase “or as otherwise made effective
pursuant to the laws applicable to such ERO
governmental authorities;” to the second
sentence under the “Retirement of Existing
Standards” section.
December
19November 7,
2013
FERC Order issued approving PRC005-2. (The enforcement date for
PRC-005-2 will be April 1, 2015,
which is the first date entities must
be compliant with part of the
standard. The implementation plan
for PRC-005-2 includes specific
compliance dates and timeframes for
each of the Requirements. The
regulatory approval date in the U.S.
is February 24, 2014. Adopted by the
NERC Board of Trustees
2
23
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to address the
FERC directive in Order
No.758 to include
Automatic Reclosing in
maintenance programs.
11
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 calendar
yearsCalendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
12
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 calendar
years Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
13
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 calendar
months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
6 calendar
years
12 calendar
years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 calendar
years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
14
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation
of protective functions, and not having all the monitoring attributes of a
category below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
6 Calendar
Years
12 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection
System.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection
System.
15
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Any voltage and current sensing devices not havingcommunications system
with all of the following:
Continuous monitoring attributes of the category below.or periodic
automated testing for the performance of the channel using criteria
pertinent to the communications technology applied (e.g. signal level,
reflected power, or data error rate, and alarming for excessive
performance degradation). (See Table 2)
12 calendar
years Calendar
Years
Verify only the unmonitored communications system inputs
and outputs that current and voltage signal values are
providedessential to the protective relays.proper functioning of
the Protection System
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
16
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
17
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
18
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
6 Calendar Months
Inspect:
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
19
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
20
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
21
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Verify that the dc supply can perform as manufactured when ac power is
not present.
22
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
23
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
24
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
25
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 calendar
years Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 calendar
years Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 calendar
yearsCalendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
12 calendar
yearsCalendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
Control circuitry associated with protective functions and/or SPSSPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
26
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5 and, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5 and, Table 3,
and Tables 4-1 through 4-2 are conveyed from the alarm origin to the location
where corrective action can be initiated, and not having all the attributes of the
“Alarm Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
No periodic
maintenance
specified
None.
27
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified .
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 calendar
years Calendar
Years
Test and, if necessary calibrate .
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Verify:
12 calendar
years Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 calendar
years Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
28
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 calendar
years Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 calendar
yearsCalendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 calendar
yearsCalendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 calendar
yearsCalendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
29
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Alarming for power supply failure (See Table 2).
12 Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
30
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
31
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
32
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment of the Protection System
Component population, with a minimum
Segment population of 60 Components.
Segment – Protection Systems or components
of a consistent design standard, or a
particular model or type from a single
manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least
sixty (60) individual components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5 and, Table 3,
and Tables 4-1 through 4-2 until results of
maintenance activities for the Segment are available for a minimum of 30 individual
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires
corrective action, or a Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System component
configuration errors, or Protection System
application errors are not included in Countable
Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4% of the Components within the Segment, for the
greater of either the last 30 Components maintained or all Components maintained in the
previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Protection System Components and Segments and/or
description if any changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
33
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Protection System Segment maintained through a performancebased PSMP experience 4% or more Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to less than 4% of the Segment
population within 3 years.
34
Exhibit B
Implementation Plan
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC-005-3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC-005-2 – Protection System Maintenance
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth below in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2, or the combined successor standard PRC-005-3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according to PRC-005-2 (or the combined
successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, PRC-017-0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC-005-3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
2
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall remain active throughout the
phased implementation period of PRC-005-3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC-005-3. Standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty-six (156) months following applicable regulatory approval of
PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty-eight (168) months
following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of the first calendar quarter, twelve (12) calendar months following applicable regulatory approval
of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees’ adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2
or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
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October, 2013
3
2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
3.
4.
The entity shall be 100% compliant on the first day of the first calendar quarter thirty-six (36)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twentyfour (24) months following applicable regulatory approval of PRC-005-2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty-eight (48)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following the November 2012
NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
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The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
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5
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-2 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-2 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees’ adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
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Implementation Plan for Newly identified Automatic Reclosing Components due to generation
changes in the Balancing Authority Area:
This applies to PRC-005-3 and successor standards.
Additional applicable Automatic Reclosing Components may be identified because of the addition or
retirement of generating units; or increases of gross generation capacity of individual generating units
or plants within the Balancing Authority Area.
In such cases, the responsible entities must complete the maintenance activities, described in Table 4,
for the newly identified Automatic Reclosing Components prior to the end of the third calendar year
following the identification of those Components unless documented prior maintenance fulfilling the
requirements of Table 4 is available.
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
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Implementation Plan
Project 2007-17 Protection SystemsSystem and Automatic
On October 17, 2013, the
Reclosing Maintenance and Testing
Standards Committee
PRC-005-023
approved an errata change to
the implementation plan for
PRC-005-2 to add the phrase
Standards Involved
“or as otherwise made
Approval:
effective pursuant to the laws
• PRC-005-23 – Protection System and Automatic Reclosing Maintenance applicable to such ERO
governmental authorities;” to
Retirements:
the second sentence under the
“Retirement of Existing
PRC-005-2 – Protection System Maintenance
Standards” section.
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
Revised definition of “Protection System”
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System component types andand
Automatic Reclosing Component Types as well as the maximum allowable maintenance intervals
for these maintenance activities. The maintenance activities established may not be presently
performed by some entities and the established maximum allowable intervals may be shorter than
those currently in use by some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
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2
4.
The Implementation Schedule set forth in this document requires that entities develop their
revised Protection System Maintenance Program within twelve (12) months following applicable
regulatory approvals, or in those jurisdictions where no regulatory approval is required, on the first
day of the first calendar quarter twenty-four (24) months following NERC Board of Trustees’
adoption. This anticipates that it will take approximately twelve (12) months to achieve regulatory
approvals following adoption by the NERC Board of Trustees.
4.
The Implementation Schedule set forth below in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2 in accordance with this implementation plan. Each entity shall be
responsible for maintaining each of their Protection System components according to their
maintenance program already in place for the legacy standards (PRC-005-1b, PRC-008-0, PRC-011-0, and
PRC-017-0) or according to their maintenance program for PRC-005-2, but not both. Once an entity has
designated PRC-005-2 as its maintenance program for specific Protection System components, they
cannot revert to the original program for those components. , or the combined successor standard PRC005-3, in accordance with this implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System componentsand Automatic Reclosing Components.
Whether each component has last been maintained according to PRC-005-2 or under(or the
combined successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, or PRC-017-0, or
a combination thereof.
For activities being added to an entity’s program as part of PRC-005-23 implementation, evidence may
be available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-23.
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3
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0, which are being replaced by PRC-005-2,
shall remain active throughout the phased implementation period of PRC-005-23 and shall be applicable
to an entity’s Protection System componentComponent maintenance activities not yet transitioned to
PRC-005-2. 3. Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall be retired at midnight
of the day immediately prior to the first day of the first calendar quarter one hundred fifty-six (156)
months following applicable regulatory approval of PRC-005-2 or as otherwise made effective pursuant
to the laws applicable to such ERO governmental authorities; or, in those jurisdictions where no
regulatory approval is required, at midnight of the day immediately prior to the first day of the first
calendar quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees’ adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of the first calendar quarter, twelve (12) calendar months following applicable regulatory approval
of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees’ adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
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4
Implementation Plan for Requirements R1, R2 and R5:
EntitiesFor Protection System Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2
or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of less than one (1) calendar year, as established in Tables 1-1 through 1-5:
2.
For Protection System componentComponent maintenance activities with maximum allowable
intervals one (1) calendar year or more, but two (2) calendar years or less, as established in Tables
1-1 through 1-5:
3.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
eighteen (18) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter thirty (30) months following the November 2012 NERC Board of Trustees’ adoption of
PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
thirty-six (36) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter forty-eight (48) months following the November 2012 NERC Board of Trustees’
adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant with PRC-005-2 on the first day of the first calendar
quarter twenty-four (24) months following applicable regulatory approval of PRC-005-2 (or, for
generating plants with scheduled outage intervals exceeding two years, at the conclusion of the
first succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
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5
November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
4.
The entity shall be at least 60% compliant with PRC-005-2 on the first day of the first calendar
quarter thirty-six (36) months following applicable regulatory approval, of PRC-005-2 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter forty-eight (48) months following NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
forty-eight (48) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter sixty (60) months following the November 2012 NERC Board of Trustees’ adoption of
PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of six (6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant with PRC-005-2 on the first day of the first calendar
quarter thirty-six (36) months following applicable regulatory approval of PRC-005-2 (or, for
generating plants with scheduled outage intervals exceeding three years, at the conclusion of
the first succeeding maintenance outage), or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter forty-eight (48) months
following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant with PRC-005-2 on the first day of the first calendar
quarter sixty (60) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter seventy-two (72) months following the November 2012 NERC Board of Trustees’
adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
eighty-four (84) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter ninety-six (96) months following the November 2012 NERC Board of Trustees’ adoption
of PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
5.
For Protection System componentAutomatic Reclosing Component maintenance activities with
maximum allowable intervals of twelve (12six (6) calendar years, as established in Tables 1-1
through 1-5, Table 2, and Table 34:
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The entity shall be at least 30% compliant with PRC-005-2 The entity shall be at least 30%
compliant on the first day of the first calendar quarter thirty-six (36) months following
applicable regulatory approval of PRC-005-3 (or, for generating plants with scheduled outage
intervals exceeding three years, at the conclusion of the first succeeding maintenance outage),
or in those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter forty-eight (48) months following NERC Board of Trustees’ adoption of PRC005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant with PRC-005-2The entity shall be 100% compliant on
the first day of the first calendar quarter eighty-four (84) months following applicable
regulatory approval of PRC-005-3, or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter ninety-six (96) months following NERC
Board of Trustees’ adoption of PRC-005-3 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval, of PRC-005-2 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant with PRC-005-2 on the first day of the first calendar quarter
one hundred fifty-six (156) months following applicable regulatory approval, of PRC-005-2 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred sixty-eight (168) months following the November 2012 NERC
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7
Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees’ adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
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Implementation Plan for Newly identified Automatic Reclosing Components due to generation
changes in the Balancing Authority Area:
This applies to PRC-005-3 and successor standards.
Additional applicable Automatic Reclosing Components may be identified because of the addition or
retirement of generating units; or increases of gross generation capacity of individual generating units
or plants within the Balancing Authority Area.
In such cases, the responsible entities must complete the maintenance activities, described in Table 4,
for the newly identified Automatic Reclosing Components prior to the end of the third calendar year
following the identification of those Components unless documented prior maintenance fulfilling the
requirements of Table 4 is available.
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
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Exhibit C
Order No. 672 Criteria
Exhibit C — Order No. 672 Criteria — Proposed Reliability Standard PRC-005-3
Order No. 672 Criteria
In Order No. 672,1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
The purpose of proposed Reliability Standard PRC-005-3 is to document and implement
programs for the maintenance of all Protection Systems and Automatic Reclosing affecting the
reliability of the Bulk Electric System so that they are kept in working order. The revised
Reliability Standard requires that entities develop an appropriate Protection System Maintenance
Program, that they implement their program, and that, in the event they are unable to restore
Automatic Reclosing Components to proper working order while performing maintenance, they
initiate the follow-up activities necessary to resolve those maintenance issues. Proposed PRC-
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose a
topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should
be developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.
005-3 adds detailed tables of minimum maintenance activities and maximum maintenance
intervals for Automatic Reclosing to the existing PRC-005-2 Reliability Standard, extending the
benefits of a strong maintenance program to these Components. The subset of Automatic
Reclosing applications included in proposed PRC-005-3 is based on the findings of the
SAMS/SPCS Report included as Exhibit D. The proposed Reliability Standard is also designed
to fulfill the Commission’s directive in Order No. 758 regarding the addition of certain reclosing
relays to the PRC-005 Reliability Standard.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply.3
The proposed Reliability Standard is clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. Aside from minor modifications
to facilitate coverage of Automatic Reclosing in the Reliability Standard, the Requirements
previously-approved by the Commission in PRC-005-2 are unchanged. The proposed Reliability
Standard applies to Generator Owners, Transmission Owners, and Distribution Providers and
clearly articulates the actions that each entity must take to comply with the proposed Reliability
Standard.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.4
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
Because the Requirements contained in proposed Reliability Standard PRC-005-3 have
not changed compared to those contained in the Commission-approved Reliability Standard
PRC-005-2, the Standard Drafting Team determined that no revisions were necessary to the
VRFs for the proposed Reliability Standard. NERC, therefore, requests that the Commission
approve the VRFs as applied to the additional Automatic Reclosing Components now included
in the proposed Reliability Standard.
The VSLs in PRC-005-2 have been revised accordingly to add the additional Component
into the levels of severity. The changes are consistent with the approach taken for the VSLs in
Reliability Standard PRC-005-2.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner.5
The proposed Reliability Standard continues to include Measures that support the
Requirements by clearly identifying what is required and how the Requirement will be enforced.
The Measures have been slightly modified to include Automatic Reclosing references where
necessary. The proposed Measures are as follows:
M1. Each Transmission Owner, Generator Owner and Distribution
Provider shall have a documented Protection System Maintenance
Program in accordance with Requirement R1. For each Protection
System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based,
performance-based, or a combination of these maintenance methods),
and shall include all batteries associated with the station dc supply
Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance
intervals, the responsible entity(s) shall have evidence for each
Protection System and Automatic Reclosing Component Type (such as
manufacturer’s specifications or engineering drawings) of the
5
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so
that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
appropriate monitored Component attributes as specified in Tables 1-1
through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution
Provider that uses performance-based maintenance intervals shall have
evidence that its current performance-based maintenance program(s) is in
accordance with Requirement R2, which may include but is not limited
to Component lists, dated maintenance records, and dated analysis
records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution
Provider that utilizes time-based maintenance program(s) shall have
evidence that it has maintained its Protection System and Automatic
Reclosing Components included within its time-based program in
accordance with Requirement R3. The evidence may include but is not
limited to dated maintenance records, dated maintenance summaries,
dated check-off lists, dated inspection records, or dated work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution
Provider that utilizes performance-based maintenance intervals in
accordance with Requirement R2 shall have evidence that it has
implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its
performance-based program in accordance with Requirement R4. The
evidence may include but is not limited to dated maintenance records,
dated maintenance summaries, dated check-off lists, dated inspection
records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution
Provider shall have evidence that it has undertaken efforts to correct
identified Unresolved Maintenance Issues in accordance with
Requirement R5. The evidence may include but is not limited to work
orders, replacement Component orders, invoices, project schedules with
completed milestones, return material authorizations (RMAs) or
purchase orders.
These Measures help provide clarity regarding how the Requirements will be enforced,
and help ensure that the Requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design.6
The proposed Reliability Standard achieves its reliability goals effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard includes certain
applications of Automatic Reclosing as explained in the Petition and reflected in the
Applicability section of the proposed Reliability Standard. NERC engaged the NERC System
Analysis and Modeling Subcommittee (“SAMS”) and the System Protection and Control
Subcommittee (“SPCS”), both subcommittees of the NERC Planning Committee, to support the
Project 2007‐17 Standard Drafting Team assigned to modify PRC‐005. The SAMS/SPCS Report
(Exhibit D) recommends technical bases to identify those reclosing applications that may affect
the Reliable Operation of the Bulk-Power System. These applications have been included in the
Applicability section of PRC‐005 to address the directives in Order No. 758. By engaging the
NERC technical subcommittees of the Planning Committee in the analysis to determine what
applications of reclosing should be included, the proposed Reliability Standard does not overinclude applications that do not affect reliability. Engaging the technical committees in this
analysis assisted the Standard Drafting Team in reaching the most efficient and effective
determination regarding the Applicability changes in the proposed Reliability Standard.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.7
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. In addition to satisfying a Commission directive, the revisions contained in the
proposed Reliability Standard require expanded application of maintenance plans and processes,
helping to preserve reliability by addressing potential issues before they impact reliability. The
Automatic Reclosing applications included in the proposed Reliability Standard also reflect
detailed study by two of NERC’s technical subcommittees, as noted above and in the Petition.
Lastly, NERC staff conducted additional technical analysis to confirm the effectiveness of
certain aspects of the proposed Reliability Standard such as the 10-mile threshold included in the
Applicability section.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard.8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.9
Proposed Reliability Standard PRC-005-3 has no undue negative effect on competition.
The proposed Reliability Standard requires the same performance by each of the applicable
Functional Entities—Generator Owners, Transmission Owners, and Distribution Providers—in
requiring the development of maintenance plans for Automatic Reclosing.
The proposed Reliability Standard does not unreasonably restrict the available generation
or transmission capability or limit use of the Bulk-Power System in a preferential manner.
9. The implementation time for the proposed Reliability Standard is reasonable.10
The proposed effective dates for the proposed Reliability Standard are just and reasonable
and appropriately balance the urgency in the need to implement the proposed Reliability
Standard against the reasonableness of the time allowed for those who must comply to develop
necessary procedures, software, facilities, staffing or other relevant capability. This will allow
applicable entities adequate time to ensure compliance with the Requirements. The proposed
effective dates are explained in the proposed Implementation Plan, attached as Exhibit B.
Except for the addition of certain applications of Automatic Reclosing, the Implementation Plan
remains unchanged from the Commission-approved version attached to Reliability Standard
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
PRC-005-2. The same timeframes for compliance with the Requirements will apply counting
forward from the effective date of an order approving proposed PRC-005-3.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI-accredited processes for developing and approving Reliability
Standards. Exhibit H includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the Standard Drafting Team
were properly noticed and open to the public. The initial and recirculation ballots both achieved a
quorum and exceeded the required ballot pool approval levels.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of
the proposed Reliability Standard. No comments were received indicating the proposed
Reliability Standard is in conflict with other vital public interests.
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
12. Proposed Reliability Standards must consider any other appropriate factors.13
No other factors relevant to whether the proposed Reliability Standard is just and
reasonable were identified.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we
will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
Exhibit D
NERC SAMS-SPCS Joint Autoreclosing Report
Considerations for
Maintenance and Testing of
Autoreclosing Schemes
System Analysis and Modeling Subcommittee
System Protection and Control Subcommittee
November 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC’s Mission
NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory
authority established to enhance the reliability of the bulk power system in North America.
NERC develops and enforces Reliability Standards; assesses adequacy annually via a ten‐year
forecast and winter and summer forecasts; monitors the bulk power system; and educates,
trains, and certifies industry personnel. NERC is the electric reliability organization for North
America, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and
governmental authorities in Canada.1
NERC assesses and reports on the reliability and adequacy of the North American bulk power
system, which is divided into eight Regional areas, as shown on the map and table below. The
users, owners, and operators of the bulk power system within these areas account for virtually
all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte, México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability Standards
with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory and enforceable.
In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia,
Québec, and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and
New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro making reliability standards mandatory for that
entity, and Manitoba has recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and
operators in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s Transportation
Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been
recognized as standards‐setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards
to become mandatory. NERC’s reliability standards are also mandatory in Nova Scotia and British Columbia. NERC is working with the other
governmental authorities in Canada to achieve equivalent recognition.
Considerations for Maintenance and Testing of Autoreclosing Schemes
i
Table of Contents
Table of Contents
NERC’s Mission ................................................................................................................................. i
Table of Contents ............................................................................................................................ iii
Introduction .................................................................................................................................... 1
Considerations for Applicability of PRC‐005 ................................................................................... 2
Applications to Improve Bulk Power System Performance ........................................................ 2
Applications to Aid Restoration .................................................................................................. 3
Maintenance Intervals and Activities ............................................................................................. 8
Autoreclosing Relays ................................................................................................................... 8
Autoreclosing Control Circuitry .................................................................................................. 8
Recommendations ........................................................................................................................ 10
Appendix A – System Analysis and Modeling Subcommittee Roster ........................................... 11
Appendix B – System Protection and Control Subcommittee Roster .......................................... 12
This technical document was approved by the NERC Planning Committee on November 14, 2012.
Considerations for Maintenance and Testing of Autoreclosing Schemes
iii
Chapter 1 — Introduction
Introduction
On February 3, 2012, the Federal Energy Regulatory Commission (FERC) issued Order No. 7582
approving an interpretation of NERC Reliability Standard PRC‐005‐1, Transmission and
Generation Protection System Maintenance and Testing. In addition to approving the
interpretation, the Commission directed that concerns identified in the preceding Notice of
Proposed Rulemaking (NOPR) be addressed within the reinitiated PRC‐005 revisions.
The concerns raised in the NOPR pertain to automatic reclosing (autoreclosing) relays that are
either “used in coordination with a Protection System to achieve or meet system performance
requirements established in other Commission‐approved Reliability Standards, or can
exacerbate fault conditions when not properly maintained and coordinated,” in which case
“excluding the maintenance and testing of these reclosing relays will result in a gap in the
maintenance and testing of relays affecting the reliability of the Bulk‐Power System.”3 To
address these concerns, the Commission concludes that “specific requirements or selection
criteria should be used to identify reclosing relays that affect the reliability of the Bulk‐Power
System.”4
This report provides technical input from the NERC System Analysis and Modeling
Subcommittee (SAMS) and the System Protection and Control Subcommittee (SPCS), both
subcommittees of the NERC Planning Committee, to support the Project 2007‐17 standard
drafting team assigned to modify PRC‐005. This report recommends technical bases to identify
those autoreclosing applications that may affect reliability of the bulk power system. Such
applications should be included in the Applicability section of PRC‐005 to address the directives
in Order No. 758.
2
See FERC Order No. 758, Interpretation of Protection System Reliability Standard, 138 FERC ¶ 61,094.
3
Id. at P. 16.
4
Id. at P. 26.
Considerations for Maintenance and Testing of Autoreclosing Schemes
1
Chapter 2 — Considerations for Applicability of PRC‐005
Considerations for Applicability of PRC-005
Autoreclosing is utilized on transmission systems to restore transmission elements to service
following automatic circuit breaker tripping. When an autoreclosing application may affect
reliability of the bulk power system, the autoreclosing relay5 should be included in the
applicability of PRC‐005.
The concerns identified by the Commission in Order No. 758 can be grouped into two
categories:
situations in which autoreclosing fails to operate when required to maintain bulk power
system reliability; and
situations in which autoreclosing operates in manner that is not consistent with its
design, adversely affecting reliability of the bulk power system.
The following sections address these two categories of concern.
Applications to Improve Bulk Power System Performance
Consideration of Autoreclosing to Increase Operating Limits
Planning and operation of the bulk power system must consider autoreclosing applications.6
Autoreclosing following automatic circuit breaker tripping may be successful if the condition
that initiated the tripping (e.g., a fault) is no longer present, or it may be unsuccessful if the
condition is still present in which case the circuit breaker will trip again. While successful
autoreclosing enhances reliability of the bulk power system, autoreclosing into a permanent
fault may adversely affect reliability. Since the potential for autoreclosing into a permanent
fault exists for any application, it is not possible to depend on successful autoreclosing as a
means to meet the system performance requirements in the NERC Reliability Standards or to
increase the transfer limit associated with an Interconnection Reliability Operating Limit7
(IROL).
Single‐pole tripping and autoreclosing also may be used to minimize the impact to the system
for a single‐phase fault; however, the same issues exist for single‐pole autoreclosing with
regard to the potential for an autoreclose into a permanent fault after which all three poles are
tripped. In the event an autoreclosing relay fails to initiate reclosing after a single‐pole trip,
protective functions will detect the condition and trip all three poles after a time delay.
SAMS and SPCS have not identified an application in which autoreclosing is used in coordination
with a protection system to meet the system performance requirements in a NERC Reliability
5
Autoreclosing relays in this context include dedicated autoreclosing relays and the autoreclosing function in multi‐function relays.
6
For example, TPL‐001‐2, adopted by the NERC Board of Trustees on August 4, 2011, requires that analyses include the impact of subsequent
successful high‐speed autoreclosing and unsuccessful high‐speed autoreclosing into a fault where high‐speed autoreclosing is utilized.
7
Capitalized as referenced in the NERC Glossary of Terms.
2
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
Standard or in establishing an IROL. As discussed above, the need to consider autoreclosing
into a permanent fault precludes dependency on autoreclosing for this purpose. SAMS and
SPCS therefore recommend that no modification is necessary to the applicability of PRC‐005 to
address autoreclosing applications necessary for bulk power system performance.
Autoreclosing as Part of a Special Protection System
Special Protection Systems8 (SPS) may be applied to meet system performance requirements in
the NERC Reliability Standards or to increase the transfer limit associated with an IROL. When
autoreclosing is included as an integral part of such a SPS, a failure of the reclosing function
may adversely impact bulk power system reliability. NERC Reliability Standard PRC‐005‐29
includes minimum maintenance activities and maximum intervals for SPS. SAMS and SPCS
recommend that PRC‐005 be modified to explicitly address maintenance and testing of
autoreclosing relays applied as an integral part of a SPS.
Applications to Aid Restoration
Autoreclosing typically is installed to alleviate the burden on operators of manually restoring
transmission lines. Autoreclosing also provides improved availability of overhead transmission
lines. The degree to which availability is improved depends on the nature of the fault
(permanent or temporary) and on transmission operator practices for manually restoring lines.
While faster restoration of transmission lines following temporary faults does provide an
inherent reliability benefit, this section addresses applications that are not necessary to meet
system performance requirements in NERC Reliability Standards. In these applications it is
possible for undesired operation of the autoreclosing scheme, not consistent with its design, to
adversely affect system reliability. The following sections discuss credible failure modes that
may lead to undesired operation and the associated potential reliability impacts to the bulk
power system, to identify applications that should be included in the Applicability section of
PRC‐005.
Credible Failure Modes of Autoreclosing Schemes
This section discusses credible failure modes of autoreclosing schemes. These failure modes
are assessed in the next section to identify which may impact reliability of the bulk power
system. Applications for which one or more of these failure modes could adversely affect
reliability will be provided to the Project 2007‐17 standard drafting team to support
development of revisions to PRC‐005 directed in Order No. 758.
There are many different types of autoreclosing relays. Autoreclosing relays may be
electromechanical (and comprised of discrete components), solid state, or microprocessor‐
based and may be applied in a variety of autoreclosing schemes. Regardless of the type of
autoreclosing scheme or vintage of design of the autoreclosing relay, there are a few main
characteristics shared by most autoreclosing relays. These include:
8
Capitalized as referenced in the NERC Glossary of Terms.
9
PRC‐005‐2 achieved 81.08 percent quorum and 80.51 percent approval in a recirculation ballot that ended October 24, 2012.
Considerations for Maintenance and Testing of Autoreclosing Schemes
3
Chapter 2 — Considerations for Applicability of PRC‐005
Supervision Functions: Supervising elements typically monitor one or more voltage
phases to determine if a circuit is energized (live), de‐energized (dead), or in
synchronism with another circuit, etc. Other types of supervision may be used to
perform selective autoreclosing; e.g., autoreclosing is blocked for the detection of a
three‐phase fault, or for the loss of a communication channel. In some applications,
autoreclosing is unsupervised.
Timing Functions: Timing elements perform various timing duties with the most
important being the desired time delay to issue a circuit breaker close; the minimum
time delay being dictated by de‐ionization time. In some applications, autoreclosing is
initiated by protective relaying and issues a close signal with little or no intentional time
delay.
Output Function: The output function is typically some type of relay with contacts that
close and apply DC voltage to the close circuit to effect a circuit breaker close.
When analyzing autoreclosing relay failure modes, the functions described above are the ones
most likely to lead to a failure. The failures can be analyzed without a detailed discussion of the
many variations of autoreclosing logic that may be implemented throughout North America.
The main failure modes of autoreclosing relays are:
Supervision Function Failures: A failed voltage supervision function that requires a dead
line to reclose may incorrectly interpret that the monitored circuit is live and
consequently not issue a close signal to a circuit breaker as designed. Conversely, a
failed voltage supervision function that requires a live line to reclose may incorrectly
interpret that a dead circuit is live and, therefore, incorrectly issue a close signal to a
circuit breaker. Further, failure of a synchronism check function may allow a close when
static system angles are greater than designed, or inhibit a close when static system
angles are less than designed.
Timing Function Failures: Where intentional time delays are used, the time delay circuits
may fail and issue a close with no time delay. Failure of the time delay circuits may also
inhibit the autoreclosing relay from issuing a close signal.
Output Function Failures: The output relay contacts may fail to close and thus no close
signal will be issued to a circuit breaker. The output relay contacts may also fail in the
closed position (“weld shut”) and send a constant close signal to a circuit breaker. Solid
state outputs can exhibit both of these failure modes. This failure mode can result in
one of two possible scenarios depending on the circuit breaker closing circuit design and
whether the constant close signal occurs prior to tripping or during the act of reclosing
the circuit breaker. One scenario is that no reclose will occur. The second scenario will
result in only one reclose being attempted.
Thus, to assess the potential impact of an autoreclosing relay failure on the power system, the
following types of failures should be considered:
4
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
No close signal is issued under conditions that meet the intended design conditions.
This is the most common failure mode and includes the vast majority of autoreclosing
failures.
A close signal is issued with no time delay or with less time delay than is intended.
A constant or sustained close signal is issued. In this case, a multi‐shot reclose scheme
may attempt to reclose only once.
A close signal is issued for conditions other than the intended supervisory conditions.
Potential Reliability Impacts
In this section each of the identified autoreclosing failure modes is analyzed to assess the
potential for adverse impact to bulk power system reliability and the circumstances under
which impacts may occur.
1. No close signal is issued under conditions that meet the intended design conditions: A
failure to autoreclose would result in a failure to restore a single power system element.
The system already must be planned and operated considering that autoreclosing will be
unsuccessful. Thus, the impact to power system reliability for this failure mode results in a
condition the system is designed to withstand, and therefore this failure mode does not
create any additional considerations for inclusion of autoreclosing relays in PRC‐005 beyond
those related to SPS as discussed in the previous section.
2. A close signal is issued with no time delay or with less time delay than is intended: This
failure mode can result in a minimum trip‐close‐trip sequence with the two faults cleared in
primary protection operating time, and the open time between faults equal to the breaker
closing cycle time. The sequence for this failure mode results in system impact equivalent
to a high‐speed autoreclosing sequence with no delay added in the autoreclosing logic.
The potential reliability impacts of this failure mode are damage to generators and
generator instability. Autoreclosing logic typically is selected to reenergize a dead circuit
remote from generating units or strong sources to avoid adverse impacts associated with
autoreclosing into a permanent fault. Typically when autoreclosing is applied at a
generating station it is only for live‐line conditions with synchronism check; however,
applications do exist where autoreclosing from a generating station is used such as
transmission lines between two generating plants, or radial lines that cannot be energized
from another source. Where autoreclosing is applied at or in proximity to a generating
station the potential for this failure mode exists.
Premature autoreclosing has the potential to cause generating unit loss of life due to shaft
fatigue. Accepted industry guidance is that planned switching operations, such as simple
line restoration, should be conducted in a way that avoids significant contribution to
cumulative shaft fatigue. Entities typically implement this guidance at generating stations
by using time delayed autoreclosing to allow shaft oscillations to dampen, and/or live line
autoreclosing or live bus‐live line autoreclosing with synchronism check supervision to
Considerations for Maintenance and Testing of Autoreclosing Schemes
5
Chapter 2 — Considerations for Applicability of PRC‐005
minimize shaft torque. By conducting planned switching in this manner, nearly all of the
fatigue capability of the shaft is preserved to withstand the impact of unplanned and
unavoidable disturbances such as faults, fault clearing, reclosing into system faults, and
emergency line switching. Premature autoreclosing due to a supervision failure is a small
subset of autoreclosing failures (the overwhelming majority of autoreclosing failures are
failure to close) and is an infrequent unplanned disturbance. As a result, it is not necessary
to consider the incremental loss of life that may occur for this infrequent event as the basis
for whether to include maintenance and testing of autoreclosing relays in PRC‐005.
Premature autoreclosing also has the potential to cause generating unit or plant instability.
NERC Reliability Standards require consideration of loss of the largest generating unit within
a Balancing Authority Area10; therefore, generation loss would not impact reliability of the
bulk power system unless the combined capacity loss exceeds the largest unit within the
Balancing Authority Area. Including maintenance and testing of autoreclosing relays in PRC‐
005 would therefore be appropriate for applications at or in proximity to generating plants
with capacity exceeding the largest unit within the Balancing Authority Area. In this context
proximity is defined as one bus away if the bus is within 10 miles of the generating plant.
Transmission line impedance on the order of 1 mile away typically provides adequate
impedance to prevent generating unit instability and a 10 mile threshold provides sufficient
margin.
At these locations, maintenance and testing of autoreclosing relays should be subject to
PRC‐005, unless the equipment owner can demonstrate to the Transmission Planner that
this failure mode would not result in tripping generating units with combined capacity
greater than the largest unit within the Balancing Authority Area. This demonstration
should be based on simulation of a close‐in three‐phase fault for twice the normal clearing
time (capturing a minimum trip‐close‐trip time delay).
3. A constant or sustained close signal is issued: This failure mode can result in one of two
possible scenarios depending on the circuit breaker closing circuit design and whether the
constant close signal occurs prior to tripping or during the act of reclosing the circuit
breaker. One scenario is that no reclose will occur. The second scenario will result in only
one reclose being attempted. This scenario results in the worse impact; however this
results in an outcome similar to failure mode No. 1 – less reclose attempts than planned.
Neither of these failure modes creates any additional considerations for inclusion of
autoreclosing relays in PRC‐005.
4. A close signal is issued for conditions other than the intended supervisory conditions: This
failure mode can result in two different scenarios.
The first scenario is autoreclosing into a dead line with a fault when dead‐line closing was
not intended. Similar to failure mode No. 2 discussed above, the potential reliability
10
Capitalized as referenced in the NERC Glossary of Terms.
6
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
impacts of this failure mode are instability and damage to generating units. The incidence
of this failure mode is similar to failure mode No. 2 and therefore concern may be limited to
the potential loss of generating units with combined capacity that exceeds the largest unit
within the Balancing Authority Area. Including maintenance and testing of autoreclosing
relays in PRC‐005 would therefore be appropriate for applications at or in proximity to
generating units as noted above. The primary difference between this scenario and failure
mode No. 2 is this failure mode does not include a timing failure. As such both this scenario
and failure mode No. 2 can lead to unintended autoreclosing into fault; however, the timing
of the undesired autoreclosure in this scenario will occur after any intentional time delay
included in the autoreclosing relay. For this reason a separate test is not necessary to
exclude applications from maintenance and testing under PRC‐005. Application of the test
described for failure mode No. 2 adequately addresses this failure mode.
The second scenario is autoreclosing into a live line with an angle greater than the
acceptance angle necessary to prevent potential equipment damage. The potential
reliability impact of this failure mode is damage to generating units. As noted in the
discussion of failure mode No. 2, accepted industry guidance is that planned switching
operations, such as simple line restoration, should be conducted in a way that avoids
significant contribution to cumulative shaft fatigue. By conducting planned switching in this
manner, nearly all of the fatigue capability of the shaft is preserved to withstand the impact
of unplanned and unavoidable disturbances such as faults, fault clearing, reclosing into
system faults, and emergency line switching. Undesired autoreclosing at an angle greater
than the sync‐check acceptance angle due to a supervision failure is a small subset of
autoreclosing failures and is an infrequent unplanned disturbance. As a result, it is not
necessary to consider the incremental loss of life that may occur for this infrequent event as
the basis for whether to include maintenance and testing of autoreclosing relays in PRC‐
005.
Considerations for Maintenance and Testing of Autoreclosing Schemes
7
Chapter 3 — Maintenance Intervals and Activities
Maintenance Intervals and Activities
The SPCS reviewed the maximum maintenance intervals and minimum maintenance activities
proposed in reliability standard PRC‐005‐2. Specifically, the SPCS reviewed Table 1‐1 which is
applicable to protective relays and Table 1‐5 which is applicable to control circuitry associated
with protective functions (excluding distributed UFLS and distributed UVLS). The SPCS review
focused on whether any substantive differences exist between protective relays and
autoreclosing relays, or between control circuitry associated with protective functions and
circuitry associated with autoreclosing schemes, that would warrant different intervals or
activities for maintenance of autoreclosing components.
Autoreclosing Relays
The SPCS concluded that electromechanical, solid‐state, and microprocessor based
autoreclosing relays are substantially the same with respect to design and manufacturing as
their protective relay counterparts. As such, the SPCS recommends that the maximum intervals
defined in Table 1‐1 of PRC‐005‐2 should also be applicable to autoreclosing relays that may be
subject to future versions of the standard.
The SPCS also assessed the maintenance activities included in Table 1‐1 of PRC‐005‐2 and
concluded that the activities are analogous to activities performed during maintenance and
testing of autoreclosing relays and therefore Table 1‐1 should be applied to autoreclosing relays
that may be subject to future versions of the standard. For example, the activity to test and, if
necessary calibrate, non‐microprocessor relays would be applicable to testing and calibration of
electromechanical and solid‐state autoreclosing relays, and the activity to verify acceptable
measurement of power system input values would be applicable to verification of permissive
inputs used for voltage supervision and synchronism check.
Autoreclosing Control Circuitry
Similarly, the SPCS assessed the maintenance intervals and activities included in Table 1‐5 of
PRC‐005‐2 and concluded that the intervals and activities for maintaining control circuitry for
autoreclosing schemes should be similar to those established for maintaining control circuitry
associated with protective functions. The SPCS recommends that Table 1‐5 should be
applicable to control circuitry associated with autoreclosing relays that may be subject to future
versions of the standard. The SPCS also recommends that the standard drafting team include
minimum maintenance activities and maximum maintenance intervals for autoreclosing control
circuitry that parallel the maintenance activities and intervals established for protective
function control circuitry. It should be noted that, consistent with control circuitry defined for
protective functions, the SPCS does not consider internal breaker control circuitry (e.g., anti‐
pump and coil interlock circuits) to be associated with autoreclosing component maintenance.
Since the failure to close may represent a risk to reliability when breaker closing is integral to
operation of an SPS, the closing coil should be considered in PRC‐005. For use within a revision
to PRC‐005, control circuitry of autoreclosing schemes might be defined as:
8
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 3 — Maintenance intervals and Activities
“Control circuitry associated with autoreclosing schemes including the close coil, but
excluding breaker internal controls such as anti‐pump and various interlock circuits.”
Considerations for Maintenance and Testing of Autoreclosing Schemes
9
Chapter 4 — Recommendations
Recommendations
SAMS and SPCS recommend the following guidance for future development of NERC Reliability
Standard PRC‐005, Transmission and Generation Protection System Maintenance and Testing,
to address the concerns stated in FERC Order No. 758.
1. Modify PRC‐005 to explicitly address maintenance and testing of autoreclosing relays
applied as an integral part of a SPS.
2. Modify PRC‐005 to include maintenance and testing of autoreclosing relays at or in
proximity to generating plants at which the total installed capacity is greater than the
capacity of the largest generating unit within the Balancing Authority Area.
In this context, define proximity as substations one bus away if the substation is within
10 miles of the plant.
Include a provision to exclude autoreclosing relays if the equipment owner can
demonstrate to the Transmission Planner that a close‐in three‐phase fault for twice the
normal clearing time (capturing a minimum trip‐close‐trip time delay) does not result in
a total loss of generation in the interconnection exceeding the largest unit within the
Balancing Authority Area where the autoreclosing is applied.
3. Base minimum maintenance activities and maximum intervals on the activities and intervals
in PRC‐005‐2.
Develop minimum maintenance activities and maximum intervals for autoreclosing
relays similar to Table 1‐1.
Develop minimum maintenance activities and maximum intervals for control circuitry of
autoreclosing schemes similar to Table 1‐5.
For the purpose of PRC‐005, define control circuitry of autoreclosing schemes as:
“Control circuitry associated with autoreclosing schemes including the close coil, but
excluding breaker internal controls such as anti‐pump and various interlock circuits.”
10
Considerations for Maintenance and Testing of Autoreclosing Schemes
Appendix A – System Analysis and Modeling Subcommittee Roster
Appendix A – System Analysis and Modeling
Subcommittee Roster
John Simonelli
Chair
Director - Operations Support Services
ISO New England
Jonathan E. Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
K. R. Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kenneth A. Donohoo
RE – TRE
Director System Planning
Oncor Electric Delivery
G. Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Hari Singh
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager - Modeling and Reliability Assessments
Midwest Reliability Organization
Patricia E. Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Eric Mortenson, P.E.
Investor-Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Bill Harm
RE – RFC
Senior Consultant
PJM Interconnection, L.L.C.
Amos Ang, P.E.
Investor-Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Mark Byrd
RE – SERC
Manager - Transmission Planning
Progress Energy Carolinas
Greg Henry
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Gary T. Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
Considerations for Maintenance and Testing of Autoreclosing Schemes
11
Appendix B – System Protection and Control Subcommittee Roster
Appendix B – System Protection and Control
Subcommittee Roster
William J. Miller
Chair
Principal Engineer
Exelon Corporation
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
Miroslav Kostic
Canada Provincial
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Sungsoo Kim
Canada Provincial
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Michael J. McDonald
Investor-Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Jonathan Sykes
Investor-Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
George Wegh
RE – NPCC
Manager
Northeast Utilities
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Jeff Iler
RE – RFC
Senior Engineer
American Electric Power
Joe T. Uchiyama
U.S. Federal
Senior Electrical Engineer
U.S. Bureau of Reclamation
Joe Spencer
RE – SERC -- Alternate
Manager of Planning and Engineering
SERC Reliability Corporation
Daniel McNeely
U.S. Federal – Alternate
Engineer - System Protection and Analysis
Tennessee Valley Authority
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
12
Considerations for Maintenance and Testing of Autoreclosing Schemes
Exhibit E
Supplementary Reference and FAQ Document
``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
October 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ............. 2
2.2 Protection System Definition ............................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ................................ 3
2.3.1 Frequently Asked Questions: ........................................................................................ 4
2.4.1 Frequently Asked Questions: ........................................................................................ 6
3. Protection System and Automatic Reclosing Product Generations ......................................... 13
4. Definitions ................................................................................................................................. 15
4.1 Frequently Asked Questions: ......................................................................................... 16
5. Time‐Based Maintenance (TBM) Programs .............................................................................. 18
5.1 Maintenance Practices .................................................................................................... 18
5.1.1 Frequently Asked Questions: .................................................................................. 20
5.2 Extending Time-Based Maintenance ......................................................................... 21
5.2.1 Frequently Asked Questions: .................................................................................. 22
6. Condition‐Based Maintenance (CBM) Programs ...................................................................... 23
6.1 Frequently Asked Questions: .............................................................................................. 23
7. Time‐Based Versus Condition‐Based Maintenance .................................................................. 25
7.1 Frequently Asked Questions: ......................................................................................... 25
8. Maximum Allowable Verification Intervals............................................................................... 31
8.1 Maintenance Tests ........................................................................................................... 31
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 31
ii
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4 ................. 33
8.1.3 Frequently Asked Questions: .................................................................................. 34
8.2 Retention of Records ....................................................................................................... 39
8.2.1 Frequently Asked Questions: .................................................................................. 39
8.3 Basis for Table 1 Intervals .............................................................................................. 41
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .................... 42
9. Performance‐Based Maintenance Process ............................................................................... 45
9.1 Minimum Sample Size ..................................................................................................... 46
9.2 Frequently Asked Questions: ......................................................................................... 49
10. Overlapping the Verification of Sections of the Protection System ....................................... 61
10.1 Frequently Asked Questions: ....................................................................................... 61
11. Monitoring by Analysis of Fault Records ................................................................................ 62
11.1 Frequently Asked Questions: ....................................................................................... 63
12. Importance of Relay Settings in Maintenance Programs ....................................................... 64
12.1 Frequently Asked Questions: ....................................................................................... 64
13. Self‐Monitoring Capabilities and Limitations.......................................................................... 67
13.1 Frequently Asked Questions: ....................................................................................... 68
14. Notification of Protection System or Automatic Reclosing Failures ....................................... 69
15. Maintenance Activities ........................................................................................................... 70
15.1 Protective Relays (Table 1-1) ...................................................................................... 70
15.1.1 Frequently Asked Questions: ................................................................................ 70
15.2 Voltage & Current Sensing Devices (Table 1-3) ................................................... 70
15.2.1 Frequently Asked Questions: ................................................................................ 72
15.3 Control circuitry associated with protective functions (Table 1-5) .................... 73
15.3.1 Frequently Asked Questions: ................................................................................ 75
iii
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
15.4 Batteries and DC Supplies (Table 1-4) ................................................................... 77
15.4.1 Frequently Asked Questions: ................................................................................ 77
15.5 Associated communications equipment (Table 1-2) ................................................ 92
15.5.1 Frequently Asked Questions: ................................................................................ 93
15.6 Alarms (Table 2) ............................................................................................................ 96
15.6.1 Frequently Asked Questions: ................................................................................ 96
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) .................................... 97
15.7.1 Frequently Asked Questions: ................................................................................ 97
15.8 Automatic Reclosing (Table 4) .......................................................................................... 98
15.8.1 Frequently‐asked Questions .......................................................................................... 98
15.9 Examples of Evidence of Compliance ......................................................................... 99
15.9.1 Frequently Asked Questions: .................................................................................... 99
References .................................................................................................................................. 101
Figures ......................................................................................................................................... 103
Figure 1: Typical Transmission System ............................................................................. 103
Figure 2: Typical Generation System ................................................................................ 104
Figure 1 & 2 Legend – Components of Protection Systems ....................................................... 105
Appendix A .................................................................................................................................. 106
Appendix B .................................................................................................................................. 109
Protection System Maintenance Standard Drafting Team ................................................. 109
iv
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
1. Introduction and Summary
Note: This supplementary reference for PRC‐005‐3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC‐005‐1b — Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC‐011‐0 — UVLS System Maintenance and Testing
PRC‐017‐0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs. Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC‐005‐3 will replace
PRC‐005‐2 which combined and replaced PRC‐005, PRC‐008, PRC‐011 and PRC‐017. PRC‐005‐3
adds Automatic Reclosing to PRC‐005‐2. PRC‐005‐2 addressed these directed modifications and
replaces PRC‐005, PRC‐008, PRC‐011 and PRC‐017.
FERC Order 758 further directed that maintenance of reclosing relays that affect the reliable
operation of the Bulk Power System be addressed. PRC‐005‐3 addresses this directive, and,
when approved, will supersede PRC‐005‐2.
This document augments the Supplementary Reference and FAQ previously developed for PRC‐
005‐2 by including discussion relevant to Automatic Reclosing added in PRC‐005‐3.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation ‐ a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed ‐ can result
in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC‐005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC‐005‐3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC‐005‐2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
Protective relays which respond to electrical quantities,
Communications systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC‐005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in‐force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non‐transmission voltage level (Distribution
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 would
apply to this equipment. An example is underfrequency load‐shedding, which is frequently
applied well down into the distribution system to meet PRC‐007‐0.
PRC‐005‐2 replaced the existing PRC‐005, PRC‐008, PRC‐011 and PRC‐017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC‐008 was
constructed quite differently than the original PRC‐005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock‐out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC‐005‐2 replaced PRC‐011, it will be important to make the distinction
between under‐voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC‐011 is now applicable under PRC‐005‐2. An example of an under‐voltage
load‐shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC‐011 are the very same types of
devices needed in PRC‐005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
4
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non‐transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 applies to this
equipment. An example is underfrequency load‐shedding, which is frequently applied well
down into the distribution system to meet PRC‐007‐0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock‐out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non‐BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip‐test requirements. For these devices that are otherwise non‐BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock‐out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC‐005‐2, the drafting team combined legacy standards PRC‐005‐1b, PRC‐008‐
0, PRC‐011‐0, and PRC‐017‐0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
5
The intent of the drafting team is that the legacy standards be reflected in PRC‐005‐2 as
follows:
Applicability of PRC‐005‐1b for Protection Systems relating to non‐generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC‐008‐0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC‐011‐0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC‐017‐0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC‐005‐1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage‐sensing devices.
Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC‐005‐3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the BES
bus located at generating plant substations where the total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at substations
one bus away from generating plants specified in Section 4.2.6.1 when the
substation is less than 10 circuit‐miles from the generating plant substation.
4.2.6.3 Automatic Reclosing applied as an integral part of a SPS specified in Section
4.2.4.
Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
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a close‐in three‐phase fault present for twice the normal clearing time (capturing a minimum
trip‐close‐trip time delay) does not result in a total loss of gross generation in the
Interconnection exceeding the gross capacity of the largest BES unit within the Balancing
Authority Area where the Automatic Reclosing is applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal‐performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when premature
autoreclosing has the potential to cause generating unit or plant instability. A technical report,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”, is
referenced in PRC‐005‐3 and provides a more detailed discussion of these concerns.
How do I interpret Applicability Section 4.2.6 to determine applicability in the
following examples:
At my generating plant substation, I have a total of 800 MW connected to one voltage level and
200 MW connected to another voltage level. How do I determine my gross capacity? Where
do I consider Automatic Reclosing to be applicable?
Scenario number 1:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 800 MW. The two units are
essentially independent plants.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because 800 MW exceeds the largest single unit in
the BA area.
Gross Capacity
Automatic
Reclosing in scope
BES V
G
800 MW
800 MW
BES V
> 10 mi
G 200 MW
non BES V
[Essentially independent plants]
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Scenario number 2:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is a connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, reclosing into a fault on the BES system could impact the stability of the non‐BES‐
connected generating units. Therefore, the total installed gross generating capacity would be
1000 MW.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
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Scenario number 3:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation but the generating units
connected at the BES voltage level do not operate independently of the units connected at the
non BES voltage level (e.g., a combined cycle facility where 800 MW of combustion turbines are
connected at a BES voltage level whose exhaust is used to power a 200 MW steam unit
connected to a non BES voltage level. The largest single unit in the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 1000 MW. Therefore,
reclosing into a fault on the BES voltage level would result in a loss of the 800 MW combustion
turbines and subsequently result in the loss of the 200 MW steam unit because of the loss of
the heat source to its boiler.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
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Scenario 4
The 800 MW of generation is connected at 345 kV and the 200 MW is connected at 138 kV with
an autotransformer at the generating plant substation connecting the two voltage levels. The
largest single unit in the BA area is 900 MW.
In this case, the total installed gross generating capacity would be 1000 MW and section 4.2.6.1
would be applicable to both the 345 kV Automatic Reclosing Components and the 138 kV
Automatic Reclosing Components, since the total capacity of 1000 MW is larger than the largest
single unit in the BA area.
However, if the 345 kV and the 138 kV systems can be shown to be uncoupled such that the
138 kV reclosing relays will not affect the stability of the 345 kV generating units then the 138
kV Automatic Reclosing Components need not be included per section 4.2.6.1.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BOTH*
* The study detailed in Footnote 1 of the draft standard may eliminate the 138 kV
Automatic Reclosing
Components and/or the 345 kV Automatic Reclosing Components
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Why does 4.2.6.2 specify “10 circuit miles”?
As noted in “Considerations for Maintenance and Testing of Autoreclosing Schemes —
November 2012”, transmission line impedance on the order of one mile away typically provides
adequate impedance to prevent generating unit instability and a 10 mile threshold provides
sufficient margin.
Should I use MVA or MW when determining the installed gross generating plant
capacity?
Be consistent with the rating used by the Balancing Authority for the largest BES generating unit
within their area.
What value should we use for generating plant capacity in 4.2.6.1?
Use the value reported to the Balance Authority for generating plant capacity for planning and
modeling purposes. This can be nameplate or other values based on generating plant
limitations such as boiler or turbine ratings.
What is considered to be “one bus away” from the generation?
The BES voltage level bus is considered to be the generating plant substation bus to which the
generator step‐up transformer is connected. “One bus away” is the next bus, connected by
either a transmission line or transformer.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the low‐
voltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low‐voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2‐2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is unaware
of industry‐recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non‐electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2‐2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock‐out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
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3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor‐based relays have six significant traits that impact a maintenance
strategy:
Self monitoring capability ‐ the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non‐Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current‐measuring devices, and even the control
circuitry (in the form of software‐latches replacing lock‐out relays, etc.).
Any Protection System component can have self‐monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand‐held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessor‐
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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based device that results in a “lock‐out.” Thus, the software‐latch 86 that replaces an electro‐
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and automatic reclosing components are kept in working order and proper operation of
malfunctioning components is restored. A maintenance program for a specific component
includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in‐service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay .
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow‐up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three‐phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
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failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC‐005‐1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC‐005‐3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1‐1 through 1‐5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC‐005‐3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid‐state protective
relays to microprocessor‐based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance‐time‐interval‐clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time‐interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed‐end process”).
For example, a problem might be identified on a VRLA battery during a six‐month check. In
instances such as one that requiring battery replacement as part of the long‐term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six‐calendar‐month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time‐based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location ‐ for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on‐command or routinely;
the running of these tests can extend the time interval between hands‐on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
TBM – time‐based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
PBM – Performance‐Based Maintenance ‐ intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM‐
developed extended intervals when test failures or in‐service failures occur infrequently.
CBM – condition‐based maintenance – continuously or frequently reported results from
non‐disruptive self‐monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self‐diagnostics. While the term “Condition‐Based‐
Maintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status‐monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored‐basis‐time‐intervals” existing within the standard, the
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explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor‐based Protection System or Automatic Reclosing Components that
perform continuous self‐monitoring verify correct operation of most components within
the device. Self‐monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self‐monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with self‐
monitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non‐disruptive self‐monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
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TBM
1
2
3
CBM
PBM
Relationship of time‐based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition‐based Maintenance (R1) and
Performance‐Based Maintenance (R2), in addition to simple time‐based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time‐based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance‐Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off-line by tripping the
transformer’s high-side and low-side circuit breakers. What testing must be done
for this system?
This system is made up of components that are all unmonitored. Assuming a time‐based
Protection System Maintenance Program schedule (as opposed to a Performance‐Based
maintenance program), each component must be maintained per the most frequent hands‐on
activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time‐based. Default time‐based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from time‐
based maintenance. The following factors may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self‐monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition‐based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor‐based relays, self‐monitoring may not include automated
diagnostics of every component within a microprocessor.
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Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance‐Based Maintenance, or
PBM. It is also sometimes referred to as reliability‐centered maintenance, or RCM; but
PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor‐based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition‐based maintenance is the process of gathering and monitoring the information
available from modern microprocessor‐based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self‐monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non‐invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
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23
provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1‐4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device‐level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1‐4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1‐4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7. Time-Based Versus Condition-Based
Maintenance
Time‐based and condition‐based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time‐based and condition‐based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06‐16‐000) on Mandatory Reliability Standards
for the Bulk‐Power System, directed NERC to submit a modification to PRC‐005‐1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC‐005‐3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition‐based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous ‐ the time interval between verifications is
minutes or seconds. Thus, technically sound, condition‐based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time‐based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on‐site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC‐005‐3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four‐month
inspection was performed in January is due in May, but if performed in March (instead of May)
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with an internal alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented Lead‐Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1‐5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead‐acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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Vented Lead‐Acid battery without any alarms connected to SCADA
(unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition‐Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
This response may include tripping, closing, or other control actions.
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely ‐ for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters ‐ this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1‐1 through 1‐5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications‐assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub‐systems of a Protection System that need to be verified are shown.
Non‐distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non‐distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co‐located non‐BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC‐005‐3:
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First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1‐1 is for protective relays,
o Table 1‐2 is for the associated communications systems,
o Table 1‐3 is for current and voltage sensing devices,
o Table 1‐4 is for station dc supply and
o Table 1‐5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make‐up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
Next look within that table for your device and its degree of monitoring. The Tables
have different hands‐on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
This Maintenance activity is the minimum maintenance activity that must be
documented.
If your Performance‐Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands‐on maintenance activity cycles of
this component.
If your Performance‐Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands‐on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
An entity does not have to utilize the extended time intervals made available by this use
of condition‐based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance man‐
hours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC‐005‐3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC‐005‐3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance‐Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead‐acid,
valve‐regulated lead‐acid, and nickel‐cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC‐005‐3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC‐005‐3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End‐to‐end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications‐assisted trip scheme. While
this can be interpreted as a GPS‐type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally‐test the dc control circuitry. A documented Real‐time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real‐time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1‐8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology‐ and method‐neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor‐ based relays.
For relay maintenance departments that choose to test microprocessor‐based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor‐ based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time‐overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end‐to‐end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real‐time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not‐to‐exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
36
The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four‐month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time‐based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance‐Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
Fault protective functions, including distance functions, voltage‐restrained overcurrent
functions, or voltage‐controlled overcurrent functions
Loss‐of‐field relays
Volts‐per‐hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator‐ground relays
Communications‐based Protection Systems such as transfer‐trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out‐of‐step relays
Inadvertent energization protection
Breaker failure protection
For generator step‐up, generator‐connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
Transformer differential relays
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
37
Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal‐conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system‐connected station service transformers be included in
the Applicability. The generator‐connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock‐out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
38
distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non‐distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non‐distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC‐005‐1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three‐year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC‐005‐3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on‐site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance‐Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance‐time‐interval‐
clock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time‐interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
39
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC‐005‐3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged‐Fault‐tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be re‐
verified within an ongoing maintenance program. Example – it is not necessary to re‐verify
correct terminal strip wiring on an ongoing basis.
PRC‐005‐3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC‐005‐3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC‐005‐3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
40
It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non‐compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in‐service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in‐service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1‐1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto‐generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built‐in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I‐17 (Transmission Relay System
Performance Comparison). Review of the I‐17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
41
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively‐known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self‐testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1‐1 through 1‐5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10‐year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self‐monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
Relay Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
Abnormal Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self‐monitoring capability is ST (for self test).
ST = 0 if there is no self‐monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time‐interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “time‐
interval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time‐interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six‐year interval for the
electromechanical relay, instead of the five‐year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10‐year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
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facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance‐Based Maintenance process may be used to
establish maintenance intervals (PRC‐005 Attachment A Criteria for a Performance‐Based
Protection System Maintenance Program). A Performance‐Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance‐Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance‐Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance‐Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance‐Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001‐2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance‐Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro‐mechanical lock‐out relays;
likewise, one segment cannot be comprised of 60 GE lock‐out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics ‐ Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis ‐ Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
46
2
z
n 1
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance‐Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance‐Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1‐1 through 1‐5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4% Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
Performance-Based Program Evaluation Example
The 4% performance target was derived as a protection system performance target and was
selected based on the drafting team’s experience and studies performed by several utilities.
This is not derived from the performance of discrete devices. Microprocessor relays and
electromechanical relays have different performance levels. It is not appropriate to compare
these performance levels to each other. The performance of the segment should be compared
to the 4% performance criteria.
In consideration of the use of Performance Based Maintenance (PBM), the user should consider
the effects of extended testing intervals and the established 4% failure rate. In the table shown
below, the segment is 1000 units. As the testing interval (in years) increases, the number of
units tested each year decreases. The number of countable events allowed is 4% of the tested
units. Countable events are the failure of a Component requiring repair or replacement, any
corrective actions performed during the maintenance test on the units within the testing
segment (units per year), or any misoperation attributable to hardware failure or calibration
failure found within the entire segment (1000 units) during the testing year.
Example: 1000 units in the segment with a testing interval of 8 years: The number of units
tested each year will be 125 units. The total allowable countable events equals: 125 X .04 = 5.
This number includes failure of a Component requiring repair or replacement, corrective issues
found during testing, and the total number of misoperations (attributable to hardware or
calibration failure within the testing year) associated with the entire segment of 1000 units.
Example: 1000 units in the segment with a testing interval of 16 years: The number of units
tested each year will be 63 units. The total allowable countable events equals: 63 X .04 = 2.5.
As shown in the above examples, doubling the testing interval reduces the number of
allowable events by half.
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Total number of units in the segment
Failure rate
Testing
Intervals
(Years)
1
2
4
6
8
10
12
14
16
18
20
Units
Per
Year
1000.00
500.00
250.00
166.67
125.00
100.00
83.33
71.43
62.50
55.56
50.00
1000
4.00%
Acceptable Number of
Countable Events per year
40.00
20.00
10.00
6.67
5.00
4.00
3.33
2.86
2.50
2.22
2.00
Yearly Failure Rate
Based on 1000
Units in Segment
4.00%
2.00%
1.00%
0.67%
0.50%
0.40%
0.33%
0.29%
0.25%
0.22%
0.20%
Using the prior year’s data, determine the maximum allowable maintenance interval for each
Segment such that the Segment experiences Countable Events on no more than 4% of the
Components within the Segment, for the greater of either the last 30 Components maintained
or all Components maintained in the previous year.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
49
to the requirements of the Standard. The requirements established for Performance‐Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power‐plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance‐Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance‐Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance‐Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in‐service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re‐calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human‐error is not pertinent data might be in the area of testing “86” lock‐out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial six‐
year interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human‐error caused tripping
incidents. In this example the human‐error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
50
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal‐performing segments in a Performance‐Based Maintenance system. Some examples are
listed below.
The maximum allowable interval, as established by the Performance‐Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
Identifiable sub‐groups of components within the established segment, which have
been identified to be the mal‐performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance‐Based Maintenance program in
order to remain within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal‐performance.
components within the mal‐performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal‐performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC‐004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance‐Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance‐Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock‐reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1‐1‐11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6‐1‐12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock‐reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
51
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance‐Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance‐changing criteria.
Similarly, Functional Entities that want to establish a condition‐based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands‐on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1‐4).
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
52
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE‐HEA lock‐out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six‐year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
53
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
54
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V‐insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper‐sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
55
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real‐time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12‐
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
56
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested / year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
57
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off‐line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real‐time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built‐in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity‐accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
58
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note ‐ a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
59
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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10. Overlapping the Verification of Sections of the
Protection System
Tables 1‐1 through 1‐5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
Time‐based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1‐1 through 1‐5;
Monitoring as described in Tables 1‐1 through 1‐5;
A Performance‐Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto‐polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
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11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time‐interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance‐related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
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11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC‐018‐1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC‐002‐1 and PRC‐018‐1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single self‐
monitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non‐microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenance‐
activity‐time‐interval‐clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up‐rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC‐005‐3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC‐005‐3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC‐005‐3 to remove
such component(s). Obviously, prudence would dictate that an “out‐of‐service” device is truly
made inactive. There are no record requirements listed in PRC‐005‐3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC‐005‐3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC‐005‐3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
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The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self‐monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self‐monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands‐on
maintenance requirement), the manufacturers of the microprocessor‐based self‐monitoring
components in the Protection System should publish for the user a document or map that
shows:
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
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13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology‐neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early‐generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC‐005‐3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non‐electrical inputs are excluded.
Non‐microprocessor based equipment is treated differently than microprocessor‐based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
Non‐microprocessor devices must be tested with voltage and/or current applied to the
device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber‐optic Hall‐effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real‐time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
Another method for proving the voltage and/or current‐sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current‐sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all‐inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi‐meters, voltmeter, clamp‐on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re‐check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi‐pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt‐meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual‐intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This six‐
year tripping requirement can be completed as easily as tracking the Real‐time Fault‐clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit‐interrupting device should not be confused with a motor‐operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high‐speed auto‐closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred‐tripping
device without the use of communications equipment. If this high‐speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring‐operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock‐out relay
(86) that may exist in any particular trip scheme. If the lock‐out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six‐year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non‐BES interrupting devices are not required. Normally‐open contacts
that are not used to pass a trip signal and normally‐closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC‐005‐2, other alarming relay control circuits,
(i.e., SF‐6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard‐wired trip circuitry with other methods of trip‐signal conveyance
such as fiber‐optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber‐optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is
unaware of industry‐recognized testing protocol for the sensing elements. The SDT believes
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐
17, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC‐005‐3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC‐005‐3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1‐5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC‐005‐3 includes high‐speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non‐BES circuit breaker that is tripped via a Protection
System to which PRC‐005‐3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non‐black‐start) radial Loads but has a trip that originates from an under‐frequency
(81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non‐BES breaker that is tripped via a Protection
System to which PRC‐005‐3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non‐black‐start) radial Loads but has a trip that originates from a BES 115KV
line relay.
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock‐out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock‐out (86) (or auxiliary (94)) relay and the
non‐BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non‐BES circuit breaker that is tripped via a
Protection System to which PRC‐005‐3 applies, such as the generator field breaker and low‐side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non‐BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
The differential relay must be verified.
The current signals to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally‐closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
Protective relays which respond to electrical quantities,
Communications Systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1‐4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance‐Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance‐changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC‐005‐3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger ‐ The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery ‐ Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1‐4.
Emerging Technologies ‐ Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1‐4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1‐4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor‐based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one‐ to two‐
second delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp‐range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc‐supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor‐controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
Internal ohmic measurements of the cells and units of lead‐acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1‐4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve‐regulated lead‐acid, vented
lead‐acid, or nickel‐cadmium) and the maintenance activity chosen.
For example, if you have a valve‐regulated lead‐acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the six‐
month interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead‐acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six‐months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve‐regulated lead‐acid (VRLA) batteries and vented lead‐acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer‐supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead‐acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel‐cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve‐regulated lead‐acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1‐4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell‐to‐cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1‐4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1‐4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell‐to‐cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1‐4 by a Performance‐Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1‐4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1‐4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot‐checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally‐accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel‐cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel‐cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel‐cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel‐cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel‐cadmium batteries,
there are no significantly measurable properties of the nickel‐cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1‐4(c)
(Protection System Station dc supply Using nickel‐cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check‐off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check‐off per battery bank is sufficient for documentation, as long as the single check‐
off attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC‐005‐3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve‐Regulated Lead‐Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead‐Acid (VLA)
batteries were unable to be used on this new type of lead‐acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188‐2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1‐4. In cases where individual cells in a multi‐cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1‐4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead‐acid (VLA) and nickel‐cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1‐4. Because
the electrolyte level in valve‐regulated lead‐acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1‐4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved‐quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve‐regulated lead‐acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1‐4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead‐acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry‐out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1‐4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six‐month test” at Row 4 on Table 1‐4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1‐4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six‐month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline ‐ others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six‐month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1‐4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self‐
monitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1‐4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1‐4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1‐4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1‐4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1‐4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1‐4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1‐4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications‐assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications‐assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communications‐
assisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber‐optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on‐site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
On‐off power‐line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check‐back test from one terminal.
Systems which use frequency‐shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss‐of‐guard indication or alarm. For frequency‐shift power‐line carrier systems, the
guard signal level meter can also be checked.
Hard‐wired pilot wire line Protection Systems typically have pilot‐wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
On‐off power‐line carrier systems can be shown to be operational by automated
periodic power‐line carrier check‐back tests with remote alarming of failures.
Systems which use a frequency‐shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss‐of‐guard alarm or low signal level alarm.
Hard‐wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot‐wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements, including signal‐to‐noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four‐month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
Power Line Carrier (PLC) ‐ The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical‐electrical signal format converters are the associated
communications equipment
Figure 1‐2, A‐1 and A‐2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
An on‐off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check‐back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre‐determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1‐1 through 1‐5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto‐polling system; the only
requirement is that the alarm be brought to the action‐site within 24 hours. This effectively
makes manned‐stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned‐station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non‐manned‐
station, which is that if the monitored point has an alarm that is auto‐reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail‐safe “form‐b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1‐1. Voltage and current‐sensing devices have the same maintenance activity and
interval as Table 1‐3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
Verify the trip path between the relay and lock‐out and/or auxiliary tripping device(s).
Verify operation of any lock‐out and/or auxiliary tripping device(s) used in the trip
circuit.
No verification of trip path required between the lock‐out (and/or auxiliary tripping
device) and the non‐BES interrupting device.
No verification of trip path required between the relay and trip coil for circuits that have
no lock‐out and/or auxiliary tripping device(s).
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non‐BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load‐Shed relay and lock‐out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock‐out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under‐frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non‐BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock‐out relay. While many failures of these distributed system circuit breakers (or
non‐BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non‐BES device, such as a battery bank that serves both a BES circuit breaker and a non‐BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during under‐
frequency or under‐voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load‐generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC‐005‐3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC‐005‐3.
15.8.1 Frequently-asked Questions
Automatic Reclosing is a control, not a protective function; why then is Automatic
Reclosing maintenance included in the Protection System Maintenance Program
(PSMP)?
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes (separates) the Automatic Reclosing
from the Protection System. Automatic Reclosing is included in the PSMP because it is a more
pragmatic approach as compared to creating a parallel and essentially identical ‘Control System
Maintenance Program’ for the two Automatic Reclosing component types.
Our maintenance practice consists of initiating the Automatic Reclosing relay and
confirming the breaker closes properly and the close signal is released. This practice
verifies the control circuitry associated with Automatic Reclosing. Do you agree?”
The described task partially verifies the control circuit maintenance activity. To meet the
control circuit maintenance activity, responsible entities need to verify, upon initiation, that the
reclosing relay does not issue a premature closing command. As noted on page 12 of the
SAMS/SPCS report, the concern being addressed within the standard is premature
autoreclosing that has the potential to cause generating unit or plant instability. Reclosing
applications have many variations, responsible entities will need to verify the applicability of
associated supervision/conditional logic and the reclosing relay operation; then verify the
conditional logic or that the reclosing relay performs in a manner that does not result in a
premature closing command being issued.
Some examples of conditions which can result in a premature closing command are: an
improper supervision or conditional logic input which provides a false state and allows the
reclosing relay to issue an improper close command based on incorrect conditions (i.e. voltage
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supervision, equipment status, sync window verification); timers utilized for closing actuation
or reclosing arming/disarming circuitry which could allow the reclosing relay to issue an
improper close command; a reclosing relay output contact failure which could result in a made‐
up‐close condition / failure‐to‐release condition.
Why was a close-in three phase fault present for twice the normal clearing time
chosen for the Automatic Reclosing exclusion? It exceeds TPL requirements and
ignores the breaker closing time in a trip-close-trip sequence, thus making the
exclusion harder to attain.
This condition represents a situation where a close signal is issued with no time delay or with
less time delay than is intended, such as if a reclosing contact is welded closed. This failure
mode can result in a minimum trip‐close‐trip sequence with the two faults cleared in primary
protection operating time, and the open time between faults equal to the breaker closing cycle
time. The sequence for this failure mode results in system impact equivalent to a high‐speed
autoreclosing sequence with no delay added in the autoreclosing logic. It represents a failure
mode which must be avoided because it exceeds TPL requirements.
Do we have to test the various breaker closing circuit interlocks and controls such
as anti-pump?
These components are not specifically addressed within Table 4, and need not be individually
tested. They are indirectly verified by performing the Automatic Reclosing control circuitry
verification as established in Table 4.
For Automatic Reclosing that is not part of an SPS, do we have to close the circuit
breaker periodically?
No. For this application, you need only to verify that the Automatic Reclosing, upon initiation,
does not issue a premature closing command. This activity is concerned only with assuring that
a premature close does not occur, and cause generating plant instability.
For Automatic Reclosing that is part of an SPS, do we have to close the circuit
breaker periodically?
Yes. In this application, successful closing is a necessary portion of the SPS, and must be
verified.
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC standards that could, at times,
fulfill evidence requirements of this standard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
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Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check‐off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC‐016 could work for the activity tracking requirements
under this PRC‐005‐3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
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References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor‐Based
Transmission‐Line Protective Relays, Part I ‐ Explanation of the Statistics, and Part II ‐
Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016‐6
PWRD and 96WM 127‐1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR‐ 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve‐
Regulated Lead‐Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead‐Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45‐2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented Lead‐
Acid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR‐100248, 1006757, August 2002.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
101
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” ‐ Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
19. “Considerations for Maintenance and Testing of Autoreclosing Schemes,” NERC
System Analysis and Modeling Subcommittee and NERC System Protection and
Control Subcommittee, November 2012
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC‐005‐2, and also
may not be all‐inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Component of
Protection System
Includes
Excludes
Devices that use non‐electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync‐check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber‐optic systems that
carry a trip signal as well as hard‐
wired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
Tele‐protection equipment used
Communications
to convey specific information, in
systems necessary
the form of analog or digital
for correct operation
signals, necessary for the correct
of protective
operation of protective functions.
functions
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
4
5
Additional information can be found in References
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A‐1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two‐terminal pilot protection scheme to protect for line Faults, and to avoid over‐
tripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self‐monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self‐monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
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5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on‐off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check‐back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A‐2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
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contacts of a small telephone‐type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check‐back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone‐type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally‐occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC‐005‐3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front‐panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay‐carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle Ashton
Tri‐State G&T
Forrest Brock
Western Farmers Electric Cooperative
Aaron Feathers
Pacific Gas and Electric Company
Sam Francis
Oncor Electric Delivery
David Harper
NRG Texas Maintenance Services
James M. Kinney
FirstEnergy Corporation
Mark Lucas
ComEd
Kristina Marriott
ENOSERV
Al McMeekin
NERC
Michael Palusso
Southern California Edison
John Schecter
American Electric Power
William D. Shultz
Southern Company Generation
Eric A. Udren
Quanta Technology
Scott Vaughan
City of Roseville Electric Department
Matthew Westrich
American Transmission Company
Philip B. Winston
Southern Company Transmission
John A. Zipp
ITC Holdings
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Exhibit F
Table of Issues and Directives
Table of Issues and Directives
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Table of Issues and Directives Associated with PRC-005-3
Source
FERC Order
758
Directive Language
(including pg #)
27. We note that the original project to revise
Reliability Standard PRC-005 failed a recirculation
ballot in July of 2011. The project was
subsequently reinitiated to continue the efforts
to develop Reliability Standard PRC-005-2. Given
that the project to draft proposed revisions to
Reliability Standard PRC-005-1 continues in this
reinitiated effort, and the importance of
maintaining and testing reclosing relays, we
direct NERC to include maintenance and testing
of reclosing relays that can affect the reliable
operation of the Bulk-Power System, as discussed
above, within these reinitiated efforts to revise
Reliability Standard PRC-005.
Disposition
Specific minimum activities and maximum
allowable intervals are included in the draft
standard within Table 4.
Section and/or
Requirement(s)
Applicability 4.2.6
Requirement R1, R3,
Requirement R4, Table 4
Exhibit G
Analysis of Violation Risk Factors and Violation Security Levels
Violation Risk Factor and Violation
Severity Level Justifications
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC-005-2 - Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria – VRFs
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning
time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to
hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC VRF Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that VRFs assigned to Requirements of Reliability Standards in
these identified areas appropriately reflect their historical critical impact on the reliability of the
Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement VRF assignments and
the main Requirement VRF assignment.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
2
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of VRFs corresponding to Requirements that address
similar reliability goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the VRF Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms
to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and
4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s
Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the requirements.
PRC-005-3 Protection System and Automatic Reclosing Maintenance is a revision of PRC-005-2
Protection System Maintenance with the stated purpose: To document and implement programs for
the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) so that they are kept in working order.
PRC-005-3 has five (5) requirements that address the inclusion of Automatic Reclosing. A Table of
minimum maintenance activities and maximum maintenance intervals has been added to PRC-005-2
to address FERC’s directives from Order 758. The revised standard requires that entities develop an
appropriate Protection System Maintenance Program (PSMP), that they implement their PSMP, and
that, in the event they are unable to restore Automatic Reclosing Components to proper working
order while performing maintenance, they initiate the follow-up activities necessary to resolve those
maintenance issues.
The requirements of PRC-005-3 map one-to-one with the requirements of PRC-005-2. The drafting
team did not revise the VRFs for the requirements of PRC-005-3.
PRC-005-3 Requirements R1 and R2 are related to developing and documenting a Protection System
Maintenance Program. The Standard Drafting Team determined that the assignment of a VRF of
Medium was consistent with the NERC criteria that violations of these requirements could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system but are unlikely to lead to bulk electric system
instability, separation, or cascading failures. Additionally, a review of the body of existing NERC
Standards with approved VRFs revealed that requirements with similar reliability objectives in other
standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
3
PRC-005-3 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC-005-3 Requirement R5 relates to the initiation of resolution of unresolved maintenance issues,
which describe situations where an entity was unable to restore a Component to proper working
order during the performance of the maintenance activity. The Standard Drafting Team determined
that the assignment of a VRF of Medium was consistent with the NERC criteria that violation of this
requirements could directly affect the electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric system but are unlikely to lead to bulk
electric system instability, separation, or cascading failures. Additionally, a review of the body of
existing NERC Standards with approved VRFs revealed that requirements with similar reliability
objectives in other standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
4
NERC Criteria - VSLs
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
5
FERC Order on VSLs
In its June 19, 2008 Order on VSLs, FERC indicated it would use the following four guidelines for determining whether to approve VSLs:
Guideline 1: VSL Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.
Guideline 2: VSL Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: VSL Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: VSL Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
6
VRF and VSL Justifications
VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to PRC005-2 Requirement R1.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
7
VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time-based or
performance-based
maintenance, or a
combination of both. (Part 1.1)
OR
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based
maintenance, or a combination
of both. (Part 1.1)
High
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
OR
VRF and VSL Justifications
Project 2007-17.2 – PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
8
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to include applicable
station batteries in a timebased program (Part 1.1)
Moderate
High
Severe
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Component Type consistent
with the maintenance intervals
specified in Tables 1-1 through 15, Table 2, Table 3, and Table 4-1
through 4-2 where monitoring is
used to extend the maintenance
intervals beyond those specified
for unmonitored Components.
(Part 1.2).
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
9
VRF and VSL Justifications – PRC-005-3, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
VSL Level Assignments Should
Ensure Uniformity and
Consistency in the
Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
10
VRF and VSL Justifications – PRC-005-3, R1
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
11
VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to
PRC-005-2 Requirement R1.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
12
VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R2
Lower
The responsible entity uses
performance-based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
13
Proposed VSL – PRC-005-3, R2
Lower
Moderate
High
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a Segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the Segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
Segment.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
14
VRF and VSL Justifications – PRC-005-3, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
15
VRF and VSL Justifications – PRC-005-3, R2
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
16
VRF and VSL Justifications – PRC-005-3, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
17
Proposed VSL – PRC-005-3, R3
Lower
Moderate
High
Severe
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
18
VRF and VSL Justificati3ons – PRC-005-3, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
19
VRF and VSL Justifications – PRC-005-3, R3
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
20
VRF and VSL Justifications – PRC-005-3, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
21
Proposed VSL – PRC-005-3, R4
Lower
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Component Type
in accordance with their
performance-based PSMP.
Moderate
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
High
Severe
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance-based
PSMP.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
22
VRF and VSL Justifications – PRC-005-3, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
23
VRF and VSL Justifications – PRC-005-3, R4
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
24
VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from malperforming Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only requirement within approved Standards, PRC-004-2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC-022-1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC-003-2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
25
VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal-performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
26
VRF and VSL Justifications – PRC-005-3, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The Requirement in PRC-005-2 has not been implemented; consequently, there is no prior level of
compliance.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
27
VRF and VSL Justifications – PRC-005-3, R5
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
28
Exhibit H
Summary of Development History and Complete Record Development
Exhibit H — Summary of Development History and Complete Record of Development —
Proposed Reliability Standard PRC-005-3
The development record for proposed Reliability Standard PRC-005-3 is summarized
below.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give
“due weight” to the technical expertise of the ERO.1 The technical expertise of the ERO is
derived from the standard drafting team. For this project, the standard drafting team consisted of
industry experts, all with a diverse set of experiences. A roster of the team members is included
in Exhibit I.
II.
Standard Development History
A. Standard Authorization Request Development
A Standard Authorization Request (“SAR”) was approved by the Standards Committee
(“SC”) on January 17, 2013 and posted for a 30-day public comment period from April 5, 2013
through May 6, 2013. There were 24 sets of responses, including comments from approximately
93 individuals from approximately 64 companies representing 8 of the 10 industry segments.
Commenters agreed that the scope of the SAR adequately addressed the Commission’s directive
in Order No. 758.
B. First Posting
Proposed Reliability Standard PRC-005-3 was posted for a 30-day public comment
period from April 5, 2013 through May 6, 2013. There were 36 sets of responses, including
comments from approximately 143 individuals from approximately 95 companies representing 8
of the 10 industry segments.
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2)(2012).
1
The standard drafting team considered stakeholder comments and made the following
changes to proposed Reliability Standard PRC-005-3 based on those comments:
To the Definitions:
Protection System Maintenance Program (PSMP):
o Un-capitalized the term “Automatic Reclosing”
Automatic Reclosing
o Minor revisions to provide clarity:
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Segment
o Capitalized the defined term “Component”
Countable Event
o Updated to incorporate reference to new Tables 4-1 through 4-2, and added the
term “Protection System” as a modifier of Misoperation for clarity.
To the Applicability:
To add clarity, the drafting team revised 4.2.6 Facilities and each of the sections: 4.2.6.1,
4.2.6.2. and 4.2.6.3. The associated footnote was modified for congruence with the
referenced sections.
To the Requirements:
The Table reference in Requirement R1, Part 1.2 was updated to include Tables 4-1
through 4-2, and the wording was revised for clarity.
The Table reference in Requirement R3 was updated to include Tables 4-1 through 4-2.
To the Measures:
The Table reference in Measure M1 was updated to include Tables 4-1 through 4-2.
To the Compliance Section:
The drafting team added the phrase “or Automatic Reclosing” for clarity.
To the VSLs:
The Table references in the VSLs were updated to include Tables 4-1 through 4-2.
To the Version History:
The previous version history of PRC-005 was added for completeness.
To the Tables:
The Tables were updated to accommodate the addition of Tables 4-1 through 4-2.
To Attachment A:
Attachment A was updated to include Tables 4-1 through 4-2.
2
To the Supplementary Reference and FAQ document:
Additional content was added to reflect changes in the standard.
Additional Implementation Plan:
A second Implementation Plan was developed to address generation changes in the
Balancing Authority Area that result in additional locations becoming subject to the
Applicability of PRC-005-3. The document titled: “Implementation Plan for Newly
identified Automatic Reclosing Components due to generation changes in the Balancing
Authority Area”, was posted with the draft standard.
Unresolved Minority Views:
Several commenters suggested making general changes to PRC-005-2. The drafting team
responded that the SAR precludes the drafting team from making general revisions to the
standard in content or arrangement, only allowing modifications to explicitly address the
maintenance and testing of reclosing relays which can affect the reliable operation of the
Bulk Electric System. The drafting team did not make any of the suggested changes.
Several commenters were concerned about initiating the project to establish PRC-005-3
before PRC-005-2 is FERC approved. The drafting team explained that they are acting in
accordance with the schedule provide to FERC in an informational filing submitted by
NERC, in response to FERC Order 758 which stated: “By July 30, 2012, NERC should
submit to the Commission either the completed project which addresses the remaining
issues consistent with this order, or an informational filing that provides a schedule for
how NERC will address such issues in the Project 2007-17 reinitiated efforts.” In the
Order, FERC accepted NERC’s commitment to address the maintenance and testing of
reclosing relays that can affect the reliable operation of the Bulk-Power System within
the standards development process. Phase 2 (Reclosing Relays) of Project 2007-17
Protection System Maintenance and Testing was initiated to develop PRC-005-3 and
satisfy NERC’s commitment to the FERC.
A few commenters questioned the complexity of the Implementation Plan for PRC-005-3
which includes the Protection System aspects of PRC-005-2 and adds the new aspects of
Automatic Reclosing from PRC-005-3. The plan addresses the implementation of the
PRC-005-2 requirements based on the approval date of PRC-005-2 and adds the
implementation of the revised requirements that include Automatic Reclosing based on
the approval date of PRC-005-3. This approach provides clarity regarding the
implementation dates for maintenance of Protection System and Automatic Reclosing
Components. The drafting team crafted the Implementation Plan with guidance from
NERC legal staff and believes the Implementation Plan is clear once carefully reviewed.
C. Second Posting
Proposed Reliability Standard PRC-005-3 was posted for a 45-day public comment and
ballot period from July 10, 2013 through August 23, 2013. There were 41 sets of responses,
including comments from approximately 149 individuals from approximately 85 companies
3
representing 7 of the 10 industry segments. Proposed Reliability Standard PRC-005-3 received a
quorum of 78.33% and an approval 79.24%.
The standard drafting team considered stakeholder comments and made the following
changes to the Implementation Plan based on those comments:
To the Implementation Plan:
In response to comments, the drafting team incorporated the “Implementation Plan for
Newly identified Automatic Reclosing Components due to generation changes in the
Balancing Authority Area” into the full Implementation Plan to consolidate the
implementation documents. Numerous commenters disagreed with the implementation
period specified in the “Implementation Plan for Newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area” stating that it
was too short to accommodate the potential number of newly identified Automatic
Reclosing Components that could become applicable nor did it provide enough time for
potential outage coordination(s) necessary to perform the required maintenance. Upon
reconsideration, the drafting team agreed that the proposed implementation schedule for
newly identified Automatic Reclosing Components was inappropriate and could
potentially jeopardize reliability by forcing entities to take unscheduled outages to
become compliant. The drafting team deemed three years to be sufficient to avoid the
reliability concerns and permit entities to implement maintenance in a manner that would
be sustainable in the long‐term.
In response to a comment, the drafting team inserted the jurisdictional pro‐forma
language where it had been inadvertently left out of the Implementation Plan.
Additionally, NERC will file the errata change with the applicable regulatory authorities
as necessary for the PRC‐005‐2 Implementation Plan.
To avoid confusion, the drafting team modified paragraph 4 of the Background section to
remove the references to the implementation timing. The timing is already
comprehensively addressed in the implementation plan for each requirement.
To the Supplementary Reference and FAQ Document:
Additional content was provided to improve the reference document.
Unresolved Minority Views:
A few commenters objected to the development of PRC‐005‐3 prior to regulatory
approval of PRC‐ 005‐2. The drafting team advised that they are acting in accordance
with the schedule NERC provided to FERC which outlines the timeframes in which
NERC will respond to the directives of FERC Order 758 through the standards drafting
process. Specifically regarding reclose relays (Footnote 37), FERC directed NERC to:
“By July 30, 2012, NERC should submit to the Commission either the completed project
which addresses the remaining issues consistent with this order, or an informational filing
4
that provides a schedule for how NERC will address such issues in the Project 2007‐17
reinitiated efforts.”
Several commenters requested an additional requirement be included in PRC‐005‐3
mandating that Balancing Authorities provide Transmission Owners, Generator Owners,
and Distribution Providers the information identifying the current largest single
generating unit in the Balancing Authority Area (described in Applicability 4.2.6), and
notify those entities (within a specified time) when this information changes. The SAR
for this project does not permit the addition of functional entities to the Applicability
section of this standard; therefore, the drafting team is unable to make the requested
change. The drafting team understood the request but contends that such a requirement
would be more appropriately included in a Reliability Standard applicable to Balancing
Authorities; consequently, the drafting team added this issue to the NERC Issues
Database for consideration when the pertinent Reliability Standard is revised.
D. Final Ballot
Proposed Reliability Standard PRC-005-3 was posted for a 10-day final ballot period
from October 16, 2013 through October 25, 2013. The proposed Reliability Standard received a
quorum of 85.71% and an approval rating of 85.38%.
E. Board of Trustees Approval
Proposed Reliability Standard PRC-005-3 was approved by the NERC Board of Trustees
on November 7, 2013.
5
Project 2007-17.2 Protection System Maintenance and Testing Phase 2 (Reclosing Relays)
Related Files
Status:
PRC-005-3 was adopted by the NERC Board of Trustees at its November 7, 2013 meeting.
Background:
On February 3, 2012, the Federal Energy Regulatory Commission (FERC) issued Order No. 758
approving an interpretation of NERC Reliability Standard PRC‐005‐1, Transmission and
Generation Protection System Maintenance and Testing. In addition to approving the
interpretation, the Commission directed that concerns identified in the preceding Notice of
Proposed Rulemaking (NOPR) be addressed within the reinitiated PRC‐005 revisions. The
concerns raised in the NOPR pertain to automatic reclosing (autoreclosing) relays that are
either "used in coordination with a Protection System to achieve or meet system performance
requirements established in other Commission-approved Reliability Standards, or can
exacerbate fault conditions when not properly maintained and coordinated," in which case
"excluding the maintenance and testing of reclosing relays will result in a gap in the
maintenance and testing of relays affecting the reliability of the Bulk-Power System." To
address these concerns, the Commission concludes that "specific requirements or selection
criteria should be used to identify reclosing relays that affect the reliability of the Bulk-Power
System."
In response to Order No. 758, the Protection System Maintenance and Testing Standard
Drafting Team (SDT) drafted a Standard Authorization Request (SAR) to modify PRC-005 to
include the maintenance and testing of reclosing relays that can affect the reliable operation of
the Bulk-Power System. On May 10, 2012, the NERC Standards Committee (SC) accepted the
SAR and authorized that it be posted for information only along with the 3rd draft of PRC-0052. The NERC SC noted that PRC-005-2 was in the final stages of the development process,
having passed a successive ballot with 79 percent approval on June 27, 2012 and was scheduled
to be presented for approval at the November NERC Board of Trustees meeting. Consequently,
in recognition of the consensus achieved, the NERC SC determined that the drafting team
should complete the development of PRC-005-2 and immediately thereafter begin work on
PRC-005-3 which would reflect the necessary revisions to address reclosing relays.
The SDT also requested the NERC Planning Committee (PC) provide the technical input
necessary to develop the appropriate revisions to PRC-005. The NERC PC instructed the NERC
System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) to jointly perform a technical study to determine which reclosing relays
should be addressed within PRC-005 and provide advice regarding the appropriate
maintenance intervals and activities for those relays. The final report was approved by the
NERC PC on November 14, 2012 and provided to the SDT for guidance in developing
PRC-005-3.
In Order No. 758, the Commission also directed NERC to file, by July 30, 2012, either a
completed project, or an informational filing providing "a schedule for how NERC will address
such issues in the Project 2007-17 reinitiated efforts." On July 30, 2012, NERC submitted an
informational filing in compliance with Order No. 758 with a proposed schedule for addressing
reclosing relays. The project number and name are as follows: Project 2007-17.2 Protection
System Maintenance and Testing - Phase 2 (Reclosing Relays).
On January 17, 2013 the NERC SC authorized the draft SAR to be posted for industry comment
and on April 4, 2013, the SC authorized the standard to be posted for a 30-day comment
period.
Draft
Action
Dates
Results
Consideration
of Comments
PRC-005-3
Clean (41) | Redline to
Last Posted (42)
Redline to Last
Approved (43)
Final Ballot
Implementation Plan
Clean (44) | Redline to
Last Posted (45)
Info>> (48)
10/16/13 10/25/13
(Closed)
Vote>>
Summary>>
(49)
Ballot
Results>> (50)
Supporting Materials:
Supplementary
Reference and FAQ
Clean (46) | Redline to
Last Posted (47)
PRC-005-3
Ballot and NonClean (21) | Redline to
binding Poll
Last Posted (22)
Updated Info>>
(34)
Implementation Plan
Vote>>
Clean (23) | Redline to
Last Posted (24)
Comment
Implementation Plan
Period
for Newly Identified
Info>> (35)
08/14/13 08/23/13
(Closed)
07/10/13 08/23/13
(Closed)
Summary>>
(36)
Consideration
Ballot
Results>> (37) of Comments>>
(40)
Non-binding
Poll>> (38)
Automatic Reclosing
Components (25)
Comments
Received>>
(39)
Submit
Comments>>
Supporting Materials:
Unofficial Comment
Form (Word) (26)
SAR
Clean (27) | Redline to
Last Posted (28)
VRF/VSL Justification
Clean (29) | Redline to
Last Posted (30)
Join Ballot
Pool>>
07/10/13 08/08/13
(Closed)
Supplementary
Reference and FAQ
Clean (31) | Redline to
Last Posted (32)
Table of Issues and
Directives (33)
Draft SAR (1)
PRC-005-3
Clean (2) | Redline to
Last Approved (3)
Supporting Materials:
Unofficial Comment
Form (Word):
Draft SAR (4)
PRC-005-3 (5)
Implementation Plan
Clean (6) | Redline to
Last Approved (7)
VRF/VSL Justification
Clean (8) | Redline to
Last Approved (9)
Comment
Period
Info>> (16)
Submit
Comments:
Draft SAR
PRC-005-3
04/05/13 05/06/13
(Closed)
Comments
Received
Draft SAR>>
(17)
Consideration
of Comments
Draft SAR>>
(19)
PRC-005-3>>
(18)
PRC-005-3>>
(20)
Supplementary
Reference and FAQ
Clean (10) | Redline to
Last Approved (11)
Table of Issues and
Directives (12)
FERC Order 758 (13)
Informational Filing in
Compliance with
Order No. 758 (14)
SAMS-SPCS Order 758
Autoreclosing Report
(15)
Attachment 6c
Updated SAR Form
Standards Committee January 17, 2013 Agenda
E-mail completed form to
[email protected]
Standard Authorization Request Form
Request Date
January 17, 2013
SAR Requester Information
SAR Type (Check a box for each one that applies.)
Individual, Group, or Committee Name
Protection System Maintenance
Standard Drafting Team
New Standard
Primary Contact (if Group or Committee)
Charles Rogers
Revision to existing Standard
Company or Group Name
Chairman, Protection System
Maintenance Standard Drafting Team
Withdrawal of existing Standard
E-mail
Project Identified in Reliability Standards
Development Plan
(Project Number and Name:
)
Telephone
[email protected]
517-788-0027
Modification to NERC Glossary term or addition
of new term
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Brief Description of Proposed Standard Modifications/Actions (In three sentences or less, summarize the
proposed actions a drafting team will be responsible for implementing.)
The Standard Drafting Team shall modify NERC Standard PRC-005-2 to explicitly address the
maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk Electric
System.
The Standard Drafting Team shall not make general revisions to the standard in content or arrangement.
Need (Explain why the Standard is being developed or modified. Clearly indicate why the actions being
proposed are needed for maintaining or improving bulk power system reliability, including an assessment
of the reliability and market interface impacts. This is similar to the Purpose statement in a Reliability
Standard.)
Reclosing relays are applied to facilitate automatic restoration of system components following a
Protection System operation. In certain circumstances the misoperation of reclosing relays can impact
the reliability of the Bulk Electric System. The Federal Energy Regulatory Commission, in paragraphs 1627 of Order No. 758, directed that NERC include reclosing relays that “can affect the reliable operation
of the Bulk-Power System” within NERC Standard PRC-005
Modifying the standard in this fashion will impact Bulk Electric System (BES) reliability by assuring that
the reclosing relays (installed to meet performance goals of approved NERC Standards) are properly
maintained so that they may be expected to perform properly.
No market interface impacts are anticipated.
Goals (Describe what must be accomplished in order to meet the above need. This section would become
the Requirements in a Reliability Standard.)
The revision to PRC-005-2 may require that the definition of Protection System be revised to add
reclosing relays.
The Applicability section of the Standard must be modified to describe explicitly those devices that
entities are to maintain in accordance with the revised standard.
The Tables of minimum maintenance activities and maximum maintenance intervals will require
modification to include appropriate intervals and activities.
Finally, the informative Supplementary Reference Document (provided as a technical reference for PRC005-2) should be modified to provide the rationale for the maintenance activities and intervals within
the modified standard, as well as to provide application guidance to industry.
Standards Authorization Request Form
2
Objectives and/or Potential Future Metrics (Describe what the potential measure or criteria for success
may be for determining the successful implementation of this request. Provide ideas for potential metrics
to be developed and monitored in the future relative to this request, if any.)
Successful implementation of the modified standard will assure that the devices being added will
perform as needed for the conditions anticipated by those performance requirements.
Detailed Description (In three paragraphs or more, provide a detailed description of the proposed actions
a drafting team will be responsible for executing so that the team can efficiently implement this request.
While you will check applicability boxes on the following page, this description must include proportional
identification of to whom the standard should apply among industry participants.)
The drafting team shall:
1. Consider revision of the title of the Standard to appropriately address the added devices.
2. Modify the Purpose of the Standard as necessary to address reclosing relays.
3. Consider modification of the definition of Protection System to add reclosing relays.
4. Modify the Applicability section of PRC-005-2 to describe explicitly those devices that entities are
to maintain in accordance with the revised standard.
5. Modify the Tables within PRC-005-2 to include maximum intervals and minimum activities
appropriate for the devices being addressed, with consideration for the technology of the
devices and for any condition monitoring that may be in place for those devices.
6. Modify the Measures and Violation Severity Levels as necessary to address the modified
requirements.
7. Modify the informative Supplementary Reference Document (provided as a technical reference
for PRC-005-2) to provide the rationale for the maintenance activities and intervals within the
modified standard, as well as to provide application guidance to industry.
OPTIONAL: Technical Analysis Performed to Support Justification (Provide the results of any technical
study or analysis performed to justify this request. Alternatively, if deemed necessary, propose a technical
study or analysis that should be performed prior to a related standard development project being initiated
in response to this request.)
The NERC System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) have jointly performed a technical study to determine which reclosing relays
should be addressed within PRC-005 and provide advice regarding appropriate maintenance intervals
and activities for those relays. The related report was approved by the NERC Planning Committee on
November 14, 2012.
The Standard Drafting Team shall use this report as an aid in developing appropriate revisions to
PRC-005-2.
Standards Authorization Request Form
3
Reliability Functions
The Standard(s) May Apply to the Following Functions (Check box for each one that applies.)
Regional
Entity
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of the
Bulk Electric System within the region and adjacent regions.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
Standards Authorization Request Form
4
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and reliability-related services) to
serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard(s) comply with all of the following Market Interface Principles? (Select ‘yes’
or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
Standards Authorization Request Form
5
3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.
Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive information. All
market participants shall have equal opportunity to access commercially non-sensitive information
that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
NONE
Related Projects
Project ID and Title
Explanation
NONE
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Standards Authorization Request Form
6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
Description of Current Draft:
This is the first draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive issued
by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the maintenance
and testing of reclosing relays that can affect the reliable operation of the Bulk-Power System...”
Future Development Plan:
Anticipated Actions
1. Post for 30-day formal comment
Anticipated Date
April 2013
2. Post for a concurrent 45-day comment and initial ballot
June 2013
3. Conduct recirculation ballot
August 2013
Draft 1: April, 2013
1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and Automatic Reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Reclosing relay
Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti‐pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 1: April, 2013
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Table 4 which requires
corrective action or a Misoperation attributed to hardware failure or calibration failure. Misoperations
due to product design errors, software errors, relay settings different from specified settings, Protection
System Component or Automatic Reclosing configuration or application errors are not included in
Countable Events.
Draft 1: April, 2013
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1
4.2.6.1 Applied on BES Elements at generating plant substations where the total
installed generating plant capacity is greater than the capacity of the largest
generating unit within the Balancing Authority Area.
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of generation in the Interconnection exceeding the largest unit
within the Balancing Authority Area where the Automatic Reclosing is applied.
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4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
4.2.6.2 Applied on BES Elements at substations one bus away from generating
plants specified in Section 4.2.6.1
Component Type - Either any one
when the substation is less than 10
of the five specific elements of the
circuit-miles from the generating
Protection System definition or any
plant substation.
one of the two specific elements of
4.2.6.3 Applied as an integral part of a SPS
the Automatic Reclosing definition.
specified in Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System shall be included in a time-based
program as described in Table 1-4 and
Table 3.
Component – A component is any individual
1.2. Include the applicable monitored
discrete piece of equipment included in a
Component attributes applied to each
Protection System or in Automatic Reclosing,
Protection System Component Type and
including but not limited to a protective relay,
Automatic Reclosing Components
reclosing relay, or current sensing device. The
consistent with the maintenance
designation of what constitutes a control circuit
intervals specified in Tables 1-1 through
component is very dependent upon how an entity
1-5, Table 2, Table 3, and Table 4 where
performs and tracks the testing of the control
monitoring is used to extend the
circuitry. Some entities test their control circuits
maintenance intervals beyond those
on a breaker basis whereas others test their
specified for unmonitored Protection
circuitry on a local zone of protection basis. Thus,
System and Automatic Reclosing
entities are allowed the latitude to designate their
Components.
own definitions of control circuit components.
Another example of where the entity has some
R2. Each Transmission Owner, Generator Owner,
discretion on determining what constitutes a single
and Distribution Provider that uses
component is the voltage and current sensing
performance-based maintenance intervals in
devices, where the entity may choose either to
its PSMP shall follow the procedure
designate a full three-phase set of such devices or a
established in PRC-005 Attachment A to
single device as a single component.
establish and maintain its performance-based
intervals. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
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5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4. [Violation Risk Factor: High] [Time
Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner,
Unresolved Maintenance Issue - A
deficiency identified during a
maintenance activity that causes the
component to not meet the intended
performance, cannot be corrected
during the maintenance interval, and
requires follow-up corrective action.
and Distribution Provider that utilizes
performance-based maintenance program(s) in
accordance with Requirement R2 shall
implement and follow its PSMP for its
Protection System and Automatic Reclosing
Components that are included within the
performance-based program(s). [Violation
Risk Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Draft 1: April, 2013
6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Draft 1: April, 2013
7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System Component, or all performances of each distinct maintenance
activity for the Protection System Component since the previous scheduled audit date,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Draft 1: April, 2013
8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
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9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Table 4.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 4.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Table 4.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
their performance-based PSMP.
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance-based
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance-based
Draft 1: April, 2013
10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
Draft 1: April, 2013
Moderate VSL
High VSL
Severe VSL
PSMP.
their performance-based PSMP.
PSMP.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
2
November 2012
Complete revision, absorbing maintenance
requirements from PRC-005-1b, PRC-0080, PRC-011-0, PRC-017-0
Complete revision
3
TBD
Revision to include Automatic Reclosing
into existing Version
Inclusion of Automatic
Reclosing only
Draft 1: April, 2013
Change Tracking
12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
Test and, if necessary calibrate
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 Calendar Years
Operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 1: April, 2013
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 1: April, 2013
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a
category below.
6 Calendar Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and
outputs that are essential to proper functioning of the
Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and
outputs that are essential to proper functioning of the
Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar Years
Verify only the unmonitored communications system inputs
and outputs that are essential to proper functioning of the
Protection System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Draft 1: April, 2013
15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 1: April, 2013
Maximum
Maintenance
Interval
12 Calendar Years
No periodic
maintenance
specified
Maintenance Activities
Verify that current and voltage signal values are provided to
the protective relays.
None.
16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 1-4(f).
Battery continuity
Battery terminal connection resistance
18 Calendar Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
Physical condition of battery rack
Draft 1: April, 2013
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
18 Calendar Months
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery
performance (e.g. internal ohmic values or float current) against
the station battery baseline.
-or-
-or6 Calendar Years
Draft 1: April, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test
of the entire battery bank.
18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
Draft 1: April, 2013
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 1: April, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of
the entire battery bank.
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply Nickel-Cadmium (NiCad)
batteries not having monitoring attributes of Table 1-4(f).
Battery continuity
18 Calendar Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Draft 1: April, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of
the entire battery bank.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 1: April, 2013
Verify that the dc supply can perform as manufactured when ac power
is not present.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only non-BES interrupting
devices as part of a SPS, non-distributed UFLS, or non-distributed UVLS
system and not having monitoring attributes of Table 1-4(f).
Draft 1: April, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring and
alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring and
alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring and
alarming to ensure correct float voltage is being applied on the
station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and alarming
of battery string continuity (See Table 2).
No periodic
maintenance specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and alarming
of the intercell and/or terminal connection detail resistance of the
entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-Acid
(VLA) station battery with internal ohmic value or float current
monitoring and alarming, and evaluating present values relative to
baseline internal ohmic values for every cell/unit (See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-Acid
(VLA) station battery with monitoring and alarming of each
cell/unit internal ohmic value (See Table 2).
Draft 1: April, 2013
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or
mitigating devices (regardless of any monitoring of the control circuitry).
6 Calendar Years
Verify that each trip coil is able to operate the circuit breaker,
interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from
the protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar Years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 Calendar Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions
inclusive of all auxiliary relays.
12 Calendar Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPS whose
integrity is monitored and alarmed (See Table 2).
Draft 1: April, 2013
No periodic
maintenance
specified
None.
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Table 4 alarm attributes used to justify extended maximum maintenance intervals and/or reduced
maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Table 4 are conveyed from the alarm origin to the location where corrective
action can be initiated, and not having all the attributes of the “Alarm Path with
monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 1: April, 2013
No periodic
maintenance
specified
None.
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Settings are as specified.
12 Calendar Years
Operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 1: April, 2013
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar Years
Verify that current and/or voltage signal values are provided
to the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar Years
Verify electrical operation of electromechanical lockout
and/or tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES
interrupting devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance specified
None.
Draft 1: April, 2013
28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
Test and, if necessary calibrate
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic
Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Settings are as specified.
12 Calendar Years
Alarming for power supply failure (See Table 2).
Unmonitored Control circuitry associated with Automatic Reclosing
including the close coil.
Control circuitry associated with Automatic Reclosing including the close coil
whose integrity is monitored and alarmed (See Table 2).
Draft 1: April, 2013
12 Calendar Years
No periodic
maintenance
specified
Operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic
Reclosing.
Verify the Automatic Reclosing control path including the
close coil.
None.
29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment, with a minimum Segment
population of 60 Components.
Segment – Components of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least
sixty (60) individual components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5, Table 3, and
Table 4 until results of maintenance
activities for the Segment are available for
a minimum of 30 individual Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Table 4
which requires corrective action, or a
Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product
design errors, software errors, relay settings
different from specified settings, Protection System
Component or Automatic Reclosing configuration
or application errors are not included in
Countable Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences Countable Events on no more than 4% of the
Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
Draft 1: April, 2013
30
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
Draft 1: April, 2013
31
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
Description of Current Draft:
This is the first draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive issued
by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the maintenance
and testing of reclosing relays that can affect the reliable operation of the Bulk-Power System...”
Future Development Plan:
Anticipated Actions
1. Post for 30-day formal comment
Anticipated Date
April 2013
2. Post for a concurrent 45-day comment and initial ballot
June 2013
3. Conduct recirculation ballot
August 2013
Draft 1: April, 2013
1
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and Automatic Reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Reclosing relay
Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti‐pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 1: April, 2013
2
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Table 4 which requires
corrective action or a Misoperation attributed to hardware failure or calibration failure. Misoperations
due to product design errors, software errors, relay settings different from specified settings, Protection
System Component or Automatic Reclosing configuration or application errors are not included in
Countable Events.
Draft 1: April, 2013
3
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-23
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that these Protection Systemsthey are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1
4.2.6.1 Applied on BES Elements at generating plant substations where the total
installed generating plant capacity is greater than the capacity of the largest
generating unit within the Balancing Authority Area.
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of generation in the Interconnection exceeding the largest unit
within the Balancing Authority Area where the Automatic Reclosing is applied.
Draft 1: April, 2013
4
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
4.2.6.2 Applied on BES Elements at substations one bus away from generating
plants specified in Section 4.2.6.1
Component Type - Either any one
when the substation is less than 10
of the five specific elements of the
circuit-miles from the generating
Protection System definition or any
plant substation.
one of the two specific elements of
4.2.6.3 Applied as an integral part of a SPS
the Automatic Reclosing definition.
specified in Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner,
and Distribution Provider shall establish a
Protection System Maintenance Program
(PSMP) for its Protection Systems and
Automatic Reclosing identified in Facilities
Section 4.2. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method
(time-based, performance-based per
PRC-005 Attachment A, or a
combination) is used to address each
Protection System and Automatic
Reclosing Component Type. All
batteries associated with the station dc
supply Component Type of a Protection
System shall be included in a timebased program as described in Table 1-4
and Table 3.
1.2. Include the applicable monitored
Component attributes applied to each
Protection System Component Type and
Automatic Reclosing Components
consistent with the maintenance
intervals specified in Tables 1-1 through
1-5, Table 2, Table 3, and Table 34
where monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System and Automatic Reclosing
Draft 1: April, 2013
Component – A component is any individual
discrete piece of equipment included in a
Protection System, including but not limited to
a protective relay or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
Component Type - Any one of the five specific
elements of the Protection System definition.
Component – A component is any individual
discrete piece of equipment included in a
Protection System or in Automatic Reclosing,
including but not limited to a protective relay,
reclosing relay, or current sensing device. The
designation of what constitutes a control circuit
component is very dependent upon how an entity
performs and tracks the testing of the control
circuitry. Some entities test their control circuits
on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their
own definitions of control circuit components.
Another example of where the entity has some
discretion on determining what constitutes a single
component is the voltage and current sensing
devices, where the entity may choose either to
designate a full three-phase set of such devices or a
single device as a single component.
5
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Components.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations
Planning]
Unresolved Maintenance Issue - A
R3. Each Transmission Owner, Generator Owner,
deficiency identified during a
maintenance activity that causes the
component to not meet the intended
performance, cannot be corrected
during the maintenance interval, and
requires follow-up corrective action.
and Distribution Provider that utilizes timebased maintenance program(s) shall maintain
its Protection System and Automatic Reclosing
Components that are included within the timebased maintenance program in accordance with
the minimum maintenance activities and
maximum maintenance intervals prescribed
within Tables 1-1 through 1-5, Table 2, Table 3, and Table 34. [Violation Risk Factor: High]
[Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
Draft 1: April, 2013
6
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each protectionProtection System and Automatic Reclosing
Component Type (such as manufacturer’s specifications or engineering drawings) of the
appropriate monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2,
Table 3, and Table 34. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Draft 1: April, 2013
7
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System Component, or all performances of each distinct maintenance
activity for the Protection System Component since the previous scheduled audit date,
whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Draft 1: April, 2013
8
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, Table 3, and
Table 34 where monitoring is used
to extend the maintenance intervals
beyond those specified for
unmonitored Protection System
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entityentity’s
PSMP failed to specify whether
threefour or more Component
Types are being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
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9
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the sSegment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Table 34.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
total Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 34.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the total Components included
within a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Table 34.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 15% of the total
Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 34.
R4
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
5% or less of the annual scheduled
maintenance for a specific Protection
System Component Type in
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
annual scheduled maintenance for a
specific Protection System
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the annual scheduled maintenance
for a specific Protection System
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
more than 15% of the annual
scheduled maintenance for a
specific Protection System
Draft 1: April, 2013
10
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
accordance with their performancebased PSMP.
Component Type in accordance
with their performance-based
PSMP.
Component Type in accordance with
their performance-based PSMP.
Component Type in accordance
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Draft 1: April, 2013
11
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July
2012March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving
interpretation of R1, R1.1, and R1.2
(FERC’s Order dated March 14, 2012).
Updated version from 1a to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
Draft 1: April, 2013
12
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
2
November 7,
2012
3
TBD
Draft 1: April, 2013
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
Adopted by Board of TrusteesComplete
revision, absorbing maintenance
requirements from PRC-005-1b, PRC-0080, PRC-011-0, PRC-017-0
Complete revision,
absorbing maintenance
requirements from PRC005-1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revision to include Automatic Reclosing
into existing Version
Inclusion of Automatic
Reclosing only
13
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
Test and, if necessary calibrate
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 Calendar Years
Operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 1: April, 2013
14
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 1: April, 2013
15
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a
category below.
6 Calendar Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and
outputs that are essential to proper functioning of the
Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and
outputs that are essential to proper functioning of the
Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar Years
Verify only the unmonitored communications system inputs
and outputs that are essential to proper functioning of the
Protection System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Draft 1: April, 2013
16
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 1: April, 2013
Maximum
Maintenance
Interval
12 Calendar Years
No periodic
maintenance
specified
Maintenance Activities
Verify that current and voltage signal values are provided to
the protective relays.
None.
17
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 1-4(f).
Battery continuity
Battery terminal connection resistance
18 Calendar Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are
visible – or measure battery cell/unit internal ohmic values
where the cells are not visible
Physical condition of battery rack
Draft 1: April, 2013
18
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
18 Calendar Months
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery
performance (e.g. internal ohmic values or float current) against
the station battery baseline.
-or-
-or6 Calendar Years
Draft 1: April, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test
of the entire battery bank.
19
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
Draft 1: April, 2013
20
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 1: April, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of
the entire battery bank.
21
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Float voltage of battery charger
Protection System Station dc supply Nickel-Cadmium (NiCad)
batteries not having monitoring attributes of Table 1-4(f).
Battery continuity
18 Calendar Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Draft 1: April, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of
the entire battery bank.
22
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or non-distributed UVLS systems is
excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 1: April, 2013
Verify that the dc supply can perform as manufactured when ac power
is not present.
23
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only non-BES interrupting
devices as part of a SPS, non-distributed UFLS, or non-distributed UVLS
system and not having monitoring attributes of Table 1-4(f).
Draft 1: April, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
24
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring and
alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring and
alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring and
alarming to ensure correct float voltage is being applied on the
station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and alarming
of battery string continuity (See Table 2).
No periodic
maintenance specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and alarming
of the intercell and/or terminal connection detail resistance of the
entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-Acid
(VLA) station battery with internal ohmic value or float current
monitoring and alarming, and evaluating present values relative to
baseline internal ohmic values for every cell/unit (See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented Lead-Acid
(VLA) station battery with monitoring and alarming of each
cell/unit internal ohmic value (See Table 2).
Draft 1: April, 2013
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
25
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or
mitigating devices (regardless of any monitoring of the control circuitry).
6 Calendar Years
Verify that each trip coil is able to operate the circuit breaker,
interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from
the protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar Years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 Calendar Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions
inclusive of all auxiliary relays.
12 Calendar Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPS whose
integrity is monitored and alarmed (See Table 2).
Draft 1: April, 2013
No periodic
maintenance
specified
None.
26
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Table 3,4 alarm attributes used to justify extended maximum maintenance intervals and/or reduced
maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Table 34 are conveyed from the alarm origin to the location where corrective
action can be initiated, and not having all the attributes of the “Alarm Path with
monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 1: April, 2013
No periodic
maintenance
specified
None.
27
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Test and, if necessary calibrate
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Settings are as specified.
12 Calendar Years
Operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 1: April, 2013
28
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar Years
Verify that current and/or voltage signal values are provided
to the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar Years
Verify electrical operation of electromechanical lockout
and/or tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES
interrupting devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance specified
None.
Draft 1: April, 2013
29
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
Test and, if necessary calibrate
6 Calendar Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic
Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Settings are as specified.
12 Calendar Years
Alarming for power supply failure (See Table 2).
Unmonitored Control circuitry associated with Automatic Reclosing
including the close coil.
Control circuitry associated with Automatic Reclosing including the close coil
whose integrity is monitored and alarmed (See Table 2).
Draft 1: April, 2013
12 Calendar Years
No periodic
maintenance
specified
Operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic
Reclosing.
Verify the Automatic Reclosing control path including the
close coil.
None.
30
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment of the Protection System
Component population, with a minimum
Segment population of 60 Components.
Segment – Protection Systems or
componentsComponents of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least
sixty (60) individual components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5, Table 3, and
Table 34 until results of maintenance
activities for the Segment are available for a minimum of 30 individual Components of
the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4% of
the Components within the Segment, for
the greater of either the last 30
Components maintained or all
Components maintained in the previous
year.
To maintain the technical justification for the
ongoing use of a performance-based PSMP:
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Table 4
which requires corrective action, or a
Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product
design errors, software errors, relay settings
different from specified settings, Protection System
Component or Automatic Reclosing configuration
or application errors are not included in
Countable Events.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires
corrective action, or a Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System component
configuration errors, or Protection System
application errors are not included in Countable
Events.
1. At least annually, update the list of
Protection System Components and Segments and/or description if any changes occur
within the Segment.
Draft 1: April, 2013
31
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Protection System Segment maintained through a performancebased PSMP experience 4% or more Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to less than 4% of the Segment
population within 3 years.
Draft 1: April, 2013
32
Unofficial Comment Form
Project 2007-17.2 Protection System Maintenance – Phase 2
(Reclosing Relays) SAR for PRC-005-3
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard Authorization Request (SAR). The electronic comment form must be
completed by 8 p.m. ET, May 6, 2013.
If you have questions please contact Al McMeekin at [email protected] or by telephone at 803-5301963.
2007-17.2 Project Page
Background Information
This posting is soliciting informal comment.
In response to Order No. 758, the Protection System Maintenance and Testing Standard Drafting Team
drafted a Standard Authorization Request (SAR) to modify PRC-005 to include the maintenance and
testing of reclosing relays that can affect the reliable operation of the Bulk-Power System. On May 10,
2012, the NERC Standards Committee (SC) accepted the SAR and authorized that it be posted for
information only along with the 3rd draft of PRC-005-2. The NERC SC noted that PRC-005-2 was in the
final stages of the development process, having passed a successive ballot with 79 percent approval on
June 27, 2012 and was scheduled to be presented for approval at the November 2012 NERC Board of
Trustees meeting. Consequently, in recognition of the consensus achieved, the NERC SC determined that
the drafting team should complete the development of PRC-005-2 and immediately thereafter begin work
on PRC-005-3 which would reflect the necessary revisions to address reclosing relays.
The scope of this project includes:
The Applicability section of the Standard must be modified to describe explicitly those devices
that entities are to maintain in accordance with the revised standard.
The Tables of minimum maintenance activities and maximum maintenance intervals will require
modification to include appropriate intervals and activities.
The informative Supplementary Reference Document (provided as a technical reference for PRC005-2) should be modified to provide the rationale for the maintenance activities and intervals
within the modified standard, as well as to provide application guidance to industry.
Questions
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.
1. Do you agree that the scope of this SAR addresses the regulatory directive associated with FERC
Order No. 758? If not, please explain.
Yes
No
Comments:
2. Are you aware of any regional variances that will be needed as a result of this project? If yes,
please identify the regional variance.
Yes
No
Comments:
3. Are you aware of any business practice that will be needed or that will need to be modified as a
result of this project? If yes, please identify the business practice.
Yes
No
Comments:
4. If you have any other comments on this SAR that you haven’t already mentioned, please provide
them here:
Comments:
Unofficial Comment Form SAR for PRC-005-3
Project 2007-17.2 Protection System Maintenance – Phase II (Reclosing Relays)
2
Unofficial Comment Form
1st Draft of PRC-005-3: Protection System and Automatic
Reclosing Maintenance (Project 2007-17.2)
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the 1st draft of the standard PRC-005-3 for Protection System and Automatic Reclosing
Maintenance. The electronic comment form must be completed by 8 p.m. ET May 6, 2013.
If you have questions please contact Al McMeekin at [email protected] or by telephone at 803-5301963.
2007-17.2 Project Page
Background Information
On February 3, 2012, the Federal Energy Regulatory Commission (FERC or Commission) issued Order No.
758 approving an interpretation of NERC Reliability Standard PRC‐005‐1, Transmission and Generation
Protection System Maintenance and Testing. In addition to approving the interpretation, the Commission
directed that concerns identified in the preceding Notice of Proposed Rulemaking (NOPR) be addressed
within the reinitiated PRC‐005 revisions. The concerns raised in the NOPR pertain to automatic reclosing
(autoreclosing) relays that are either “used in coordination with a Protection System to achieve or meet
system performance requirements established in other Commission‐approved Reliability Standards, or
can exacerbate fault conditions when not properly maintained and coordinated,” in which case “excluding
the maintenance and testing of these reclosing relays will result in a gap in the maintenance and testing of
relays affecting the reliability of the Bulk‐Power System.” To address these concerns, the Commission
concludes that “specific requirements or selection criteria should be used to identify reclosing relays that
affect the reliability of the Bulk‐Power System.”
In response to Order No. 758, the Protection System Maintenance and Testing Standard Drafting Team
(SDT) drafted a Standard Authorization Request (SAR) to modify PRC-005 to include the maintenance and
testing of reclosing relays that can affect the reliable operation of the Bulk-Power System. On May 10,
2012, the NERC Standards Committee (SC) accepted the SAR and authorized that it be posted for
information only along with the 3rd draft of PRC-005-2. The NERC SC noted that PRC-005-2 was in the
final stages of the development process, having passed a successive ballot with 79 percent approval on
June 27, 2012 and was scheduled to be presented for approval at the November 2012 NERC Board of
Trustees meeting. Consequently, in recognition of the consensus achieved, the NERC SC determined that
the drafting team should complete the development of PRC-005-2 and immediately thereafter begin work
on PRC-005-3 which would reflect the necessary revisions to address reclosing relays.
The SDT also requested the NERC Planning Committee (PC) provide the technical input necessary to
develop the appropriate revisions to PRC-005. The NERC PC instructed the NERC System Analysis and
Modeling Subcommittee (SAMS) and System Protection and Control Subcommittee (SPCS) to jointly
perform a technical study to determine which reclosing relays should be addressed within PRC-005 and
provide advice regarding the appropriate maintenance intervals and activities for those relays. The final
report was approved by the NERC PC on November 14, 2012 and provided to the SDT for guidance in
developing PRC-005-3.
In Order No. 758, the Commission also directed NERC to file, by July 30, 2012, either a completed project,
or an informational filing providing “a schedule for how NERC will address such issues in the Project 200717 reinitiated efforts.” On July 30, 2012, NERC submitted an informational filing in compliance with Order
No. 758 with a proposed schedule for addressing reclosing relays. The project number and name is as
follows: Project 2007-17.2 Protection System Maintenance and Testing - Phase 2 (Reclosing Relays)
On January 17, 2013, the NERC SC authorized the draft SAR be posted for formal industry comment
concurrent with project development.
The PSMTSDT is presenting Draft 1 of PRC-005-3 for a 30-day formal comment period beginning April 5,
2013 and ending May 6, 2013.
Unofficial Comment Form PRC-005-3
Project 2007-17.2 Protection System Maintenance – Phase II (Reclosing Relays)
2
Questions
You do not have to answer any questions. Enter All Comments in Simple Text Format. Bullets, numbers,
and special formatting will not be retained. Insert a “check” mark in the appropriate boxes by doubleclicking the gray areas.
NOTE: The Standards Authorization Request specifically limits this project to modifying PRC-005-2 to
address the addition of reclosing relays which can affect the reliability of the BES, and specifically
precludes general improvements to PRC-005-2.
1. The drafting team modified PRC-005-2 and its associated Supplementary Reference and FAQ
document to address Automatic Reclosing as directed in FERC Order No. 758. Do you agree with these
changes? If not, please provide specific suggestions for improvement.
Yes
No
Comments:
2. The drafting team developed an Implementation Plan for PRC-005-3 based on the Implementation
Plan for PRC-005-2 to address the addition of Automatic Reclosing. Do you agree with the
implementation plan regarding Automatic Reclosing? If not, please provide specific suggestions for
improvement.
Yes
No
Comments:
Unofficial Comment Form PRC-005-3
Project 2007-17.2 Protection System Maintenance – Phase II (Reclosing Relays)
3
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC‐005‐3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC‐005‐2 – Protection System Maintenance
PRC‐005‐1b – Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC‐011‐0 – Undervoltage Load Shedding System Maintenance and Testing
PRC‐017‐0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC‐005‐2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC‐005‐3 addresses both Protection Systems as outlined in
PRC‐005‐2 and Automatic Reclosing components. PRC‐005‐3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC‐005‐3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC‐005‐2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC‐005‐3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry‐forward requirements from PRC‐
005‐2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth in this document carries forward the implementation
schedules contained in PRC‐005‐2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC‐005‐3. According to the combined implementation plan in
this document, entities must develop their revised Protection System Maintenance Program within
twelve (12) months following applicable regulatory approvals of PRC‐005‐2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter twenty‐four
(24) months following NERC Board of Trustees adoption of PRC‐005‐2. This anticipates that it will
take approximately twelve (12) months to achieve regulatory approvals following the November
2012 adoption of PRC‐005‐2 by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally‐distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 until that entity meets
the requirements of PRC‐005‐2, or the combined successor standard PRC‐005‐3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC‐005‐2, or the combined successor standard
PRC‐005‐3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according toPRC‐005‐2 (or the combined
successor standard PRC‐005‐3), PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, PRC‐017‐0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC‐005‐3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC‐005‐3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
2
Retirement of Existing Standards:
Standards PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 shall remain active throughout the
phased implementation period of PRC‐005‐3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC‐005‐3. Standards PRC‐005‐1b, PRC‐008‐
0, PRC‐011‐0, and PRC‐017‐0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty‐six (156) months following applicable regulatory approval of
PRC‐005‐2, or in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty‐eight (168) months
following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2.
The existing standard PRC‐005‐2 shall be retired at midnight of the day immediately prior to the first
day of first calendar quarter, twelve (12) calendar months following applicable regulatory approval of
PRC‐005‐3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC‐005‐2, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty‐four (24) months following the
November 2012 NERC Board of Trustees adoption of PRC‐005‐2, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC‐005‐3, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty‐four (24) months following
NERC Board of Trustees adoption of PRC‐005‐3, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1‐1 through 1‐5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
3
months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1‐1 through 1‐
5:
3.
4.
The entity shall be 100% compliant on the first day of the first calendar quarter thirty‐six (36)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty‐eight (48)
months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1‐1 through 1‐5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twenty‐
four (24) months following applicable regulatory approval of PRC‐005‐2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty‐six (36) months following the
November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty‐six
(36) months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter forty‐
eight (48) months following NERC Board of Trustees adoption of PRC‐005‐2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty‐eight (48)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1‐1 through 1‐5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty‐six
(36) months following applicable regulatory approval of PRC‐005‐2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
4
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty‐eight (48) months following the November 2012
NERC Board of Trustees adoption of PRC‐005‐2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty‐four (84)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety‐six (96)
months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty‐six
(36) months following applicable regulatory approval of PRC‐005‐3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty‐eight (48) months following NERC Board of Trustees
adoption of PRC‐005‐3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following NERC Board of Trustees adoption of PRC‐005‐3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty‐four (84)
months following applicable regulatory approval of PRC‐005‐3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety‐six (96)
months following NERC Board of Trustees adoption of PRC‐005‐3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1‐1 through 1‐5, Table 2, and Table 3:
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
5
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC‐005‐2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees adoption of PRC‐005‐2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty‐six (156) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty‐eight (168) months following the November 2012 NERC Board of
Trustees adoption of PRC‐005‐2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following NERC Board of Trustees adoption of PRC‐005‐3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC‐005‐3, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees adoption
of PRC‐005‐3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty‐six (156) months following applicable regulatory approval of PRC‐005‐3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty‐eight (168) months following NERC Board of Trustees adoption of
PRC‐005‐3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
6
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
Protection System and Automatic Reclosing Maintenance
Implementation Plan
April, 2013
7
Implementation Plan
Project 2007-17 Protection SystemsSystem and Automatic
Reclosing Maintenance and Testing
PRC-005-023
Standards Involved
Approval:
• PRC‐005‐23 – Protection System and Automatic Reclosing Maintenance (PRC‐005‐2)
Retirements:
PRC‐005‐2 – Protection System Maintenance
PRC‐005‐1b – Transmission and Generation Protection System Maintenance and Testing (PRC‐
005‐1b)
PRC‐008‐0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program (PRC‐008‐0)
PRC‐011‐0 – Undervoltage Load Shedding System Maintenance and Testing (PRC‐011‐0)
PRC‐017‐0 – Special Protection System Maintenance and Testing (PRC‐017‐0)
Prerequisite Approvals:
Revised definition of “Protection System”
N/A
Background:
Reliability Standard PRC‐005‐2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC‐005‐3 addresses both Protection Systems as outlined in
PRC‐005‐2 and Automatic Reclosing components. PRC‐005‐3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC‐005‐3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC‐005‐2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC‐005‐3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry‐forward requirements from PRC‐
005‐2, establish minimum maintenance activities for Protection System component types andand
Automatic Reclosing Component Types as well as the maximum allowable maintenance intervals
for these maintenance activities. The maintenance activities established may not be presently
performed by some entities and the established maximum allowable intervals may be shorter than
those currently in use by some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
Project 2007-17 Protection SystemsSystem and Automatic Reclosing Maintenance and Testing
Implementation Plan
July 2012April, 2013
2
4.
The Implementation Schedule set forth in this document requires thatcarries forward the
implementation schedules contained in PRC‐005‐2 and includes changes needed to address the
addition of Automatic Reclosing Components in PRC‐005‐3. According to the combined
implementation plan in this document, entities must develop their revised Protection System
Maintenance Program within twelve (12) months following applicable regulatory approvals of PRC‐
005‐2, or in those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter twenty‐four (24) months following NERC Board of Trustees adoption. of PRC‐005‐
2. This anticipates that it will take approximately twelve (12) months to achieve regulatory
approvals following the November 2012 adoption of PRC‐005‐2 by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally‐distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 until that entity meets
the requirements of PRC‐005‐2 in accordance with this implementation plan. Each entity shall be
responsible for maintaining each of their Protection System components according to their
maintenance program already in place for the legacy standards (PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and
PRC‐017‐0) or according to their maintenance program for PRC‐005‐2, but not both. Once an entity has
designated PRC‐005‐2 as its maintenance program for specific Protection System components, they
cannot revert to the original program for those components. , or the combined successor standard PRC‐
005‐3, in accordance with this implementation plan.
While entities are transitioning to the requirements of PRC‐005‐2, or the combined successor standard
PRC‐005‐3, each entity must be prepared to identify:
All of its applicable Protection System componentsand Automatic Reclosing Components.
Whether each component has last been maintained according to PRCtoPRC‐005‐2 or under(or
the combined successor standard PRC‐005‐3), PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, or PRC‐017‐
0, or a combination thereof.
For activities being added to an entity’s program as part of PRC‐005‐23 implementation, evidence may
be available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC‐005‐23.
Project 2007-17 Protection SystemsSystem and Automatic Reclosing Maintenance and Testing
Implementation Plan
July 2012April, 2013
2
3
Retirement of Existing Standards:
Standards PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0, which are being replaced by PRC‐005‐2,
shall remain active throughout the phased implementation period of PRC‐005‐23 and shall be applicable
to an entity’s Protection System componentComponent maintenance activities not yet transitioned to
PRC‐005‐2. 3. Standards PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0 shall be retired at midnight
of the day immediately prior to the first day of the first calendar quarter one hundred fifty‐six (156)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where no
regulatory approval is required, at midnight of the day immediately prior to the first day of the first
calendar quarter one hundred sixty‐eight (168) months following the November 2012 NERC Board of
Trustees adoption of PRC‐005‐2.
The existing standard PRC‐005‐2 shall be retired at midnight of the day immediately prior to the first
day of first calendar quarter, twelve (12) calendar months following applicable regulatory approval of
PRC‐005‐3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Project 2007-17 Protection SystemsSystem and Automatic Reclosing Maintenance and Testing
Implementation Plan
July 2012April, 2013
2
4
Implementation Plan for Requirements R1, R2 and R5:
EntitiesFor Protection System Components, entities shall be 100% compliant on the first day of the first calendar
quarter twelve (12) months following applicable regulatory approvals of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter twenty‐four (24) months following
the November 2012 NERC Board of Trustees adoption of PRC‐005‐2, or as otherwise made effective pursuant to
the laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC‐005‐3, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty‐four (24) months following
NERC Board of Trustees adoption of PRC‐005‐3, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of less than one (1) calendar year, as established in Tables 1‐1 through 1‐5:
2.
For Protection System componentComponent maintenance activities with maximum allowable
intervals one (1) calendar year or more, but two (2) calendar years or less, as established in Tables
1‐1 through 1‐5:
3.
The entity shall be 100% compliant with PRC‐005‐2 on the first day of the first calendar quarter
eighteen (18) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter thirty (30) months following the November 2012 NERC Board of Trustees adoption of
PRC‐005‐2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant with PRC‐005‐2 on the first day of the first calendar quarter
thirty‐six (36) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter forty‐eight (48) months following the November 2012 NERC Board of Trustees adoption
of PRC‐005‐2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of three (3) calendar years, as established in Tables 1‐1 through 1‐5:
The entity shall be at least 30% compliant with PRC‐005‐2 on the first day of the first calendar
quarter twenty‐four (24) months following applicable regulatory approval of PRC‐005‐2 (or, for
generating plants with scheduled outage intervals exceeding two years, at the conclusion of the
first succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty‐six (36) months following the
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5
November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
4.
The entity shall be at least 60% compliant with PRC‐005‐2 on the first day of the first calendar
quarter thirty‐six (36) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter forty‐eight (48) months following NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant with PRC‐005‐2 on the first day of the first calendar quarter
forty‐eight (48) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter sixty (60) months following the November 2012 NERC Board of Trustees adoption of
PRC‐005‐2 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
For Protection System componentComponent maintenance activities with maximum allowable
intervals of six (6) calendar years, as established in Tables 1‐1 through 1‐5 and Table 3:
The entity shall be at least 30% compliant with PRC‐005‐2 on the first day of the first calendar
quarter thirty‐six (36) months following applicable regulatory approval of PRC‐005‐2 (or, for
generating plants with scheduled outage intervals exceeding three years, at the conclusion of
the first succeeding maintenance outage), or in those jurisdictions where no regulatory
approval is required, on the first day of the first calendar quarter forty‐eight (48) months
following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant with PRC‐005‐2 on the first day of the first calendar
quarter sixty (60) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter seventy‐two (72) months following the November 2012 NERC Board of Trustees
adoption of PRC‐005‐2 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant with PRC‐005‐2 on the first day of the first calendar quarter
eighty‐four (84) months following applicable regulatory approval of PRC‐005‐2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter ninety‐six (96) months following the November 2012 NERC Board of Trustees adoption
orof PRC‐005‐2or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
5.
For Protection System componentAutomatic Reclosing Component maintenance activities with
maximum allowable intervals of twelve (12six (6) calendar years, as established in Tables 1‐1
through 1‐5, Table 2, and Table 34:
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The entity shall be at least 30% compliant with PRC‐005‐2 The entity shall be at least 30%
compliant on the first day of the first calendar quarter thirty‐six (36) months following
applicable regulatory approval of PRC‐005‐3 (or, for generating plants with scheduled outage
intervals exceeding three years, at the conclusion of the first succeeding maintenance outage),
or in those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter forty‐eight (48) months following NERC Board of Trustees adoption of PRC‐
005‐3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following NERC Board of Trustees adoption of PRC‐005‐3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant with PRC‐005‐2The entity shall be 100% compliant on
the first day of the first calendar quarter eighty‐four (84) months following applicable
regulatory approval of PRC‐005‐3, or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter ninety‐six (96) months following NERC
Board of Trustees adoption of PRC‐005‐3 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1‐1 through 1‐5, Table 2, and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC‐005‐2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC‐005‐2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees adoption of PRC‐005‐2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant with PRC‐005‐2 on the first day of the first calendar quarter
one hundred fifty‐six (156) months following applicable regulatory approval of PRC‐005‐2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred sixty‐eight (168) months following the November 2012 NERC
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Board of Trustees adoption of PRC‐005‐2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC‐005‐3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy‐two
(72) months following NERC Board of Trustees adoption of PRC‐005‐3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC‐005‐3, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees adoption
of PRC‐005‐3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty‐six (156) months following applicable regulatory approval of PRC‐005‐3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty‐eight (168) months following NERC Board of Trustees adoption of
PRC‐005‐3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
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Violation Risk Factor and Violation
Severity Level Justifications
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC‐005‐2 ‐ Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC‐approved Reliability Standards, as defined in the ERO Sanction Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria – VRFs
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning
time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to
hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC VRF Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that VRFs assigned to Requirements of Reliability Standards in
these identified areas appropriately reflect their historical critical impact on the reliability of the
Bulk‐Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub‐Requirement VRF assignments and
the main Requirement VRF assignment.
VRF and VSL Justifications
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Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of VRFs corresponding to Requirements that address
similar reliability goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the VRF Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms
to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and
4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s
Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the requirements.
PRC‐005‐3 Protection System and Automatic Reclosing Maintenance is a revision of PRC‐005‐2
Protection System Maintenance with the stated purpose: To document and implement programs for
the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) so that they are kept in working order.
PRC‐005‐3 has five (5) requirements that address the inclusion of Automatic Reclosing. A Table of
minimum maintenance activities and maximum maintenance intervals has been added to PRC‐005‐2
to address FERC’s directives from Order 758. The revised standard requires that entities develop an
appropriate Protection System Maintenance Program (PSMP), that they implement their PSMP, and
that, in the event they are unable to restore Automatic Reclosing Components to proper working
order while performing maintenance, they initiate the follow‐up activities necessary to resolve those
maintenance issues.
The requirements of PRC‐005‐3 map one‐to‐one with the requirements of PRC‐005‐2. The drafting
team did not revise the VRFs for the requirements of PRC‐005‐3.
PRC‐005‐3 Requirements R1 and R2 are related to developing and documenting a Protection System
Maintenance Program. The Standard Drafting Team determined that the assignment of a VRF of
Medium was consistent with the NERC criteria that violations of these requirements could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system but are unlikely to lead to bulk electric system
instability, separation, or cascading failures. Additionally, a review of the body of existing NERC
Standards with approved VRFs revealed that requirements with similar reliability objectives in other
standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
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PRC‐005‐3 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC‐005‐3 Requirement R5 relates to the initiation of resolution of unresolved maintenance issues,
which describe situations where an entity was unable to restore a Component to proper working
order during the performance of the maintenance activity. The Standard Drafting Team determined
that the assignment of a VRF of Medium was consistent with the NERC criteria that violation of this
requirements could directly affect the electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric system but are unlikely to lead to bulk
electric system instability, separation, or cascading failures. Additionally, a review of the body of
existing NERC Standards with approved VRFs revealed that requirements with similar reliability
objectives in other standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
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NERC Criteria - VSLs
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
VRF and VSL Justifications
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FERC Order on VSLs
In its June 19, 2008 Order on VSLs, FERC indicated it would use the following four guidelines for determining whether to approve VSLs:
Guideline 1: VSL Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior Levels of Non‐compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non‐compliance were used.
Guideline 2: VSL Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: VSL Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: VSL Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRF and VSL Justifications
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VRF and VSL Justifications
VRF and VSL Justifications – PRC‐005‐3, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal‐performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no sub‐requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC‐008‐3 Requirement R2 and FAC‐013‐2 Requirement R1, which are similar in nature to PRC‐
005‐2 Requirement R1.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal‐performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐3, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time‐based or
performance‐based
maintenance, or a
combination of both. (Part 1.1)
OR
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time‐based or
performance‐based
maintenance, or a combination
of both. (Part 1.1)
High
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time‐based or
performance‐based maintenance,
or a combination of both. (Part
1.1).
OR
VRF and VSL Justifications
Project 2007‐17.2 – PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time‐based or
performance‐based maintenance,
or a combination of both. (Part
1.1).
8
Proposed VSL – PRC‐005‐3, R1
Lower
The responsible entity’s PSMP
failed to include applicable
station batteries in a time‐
based program (Part 1.1)
Moderate
High
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Component Type consistent
with the maintenance intervals
specified in Tables 1‐1 through 1‐
5, Table 2, Table 3, and Table 4
where monitoring is used to
extend the maintenance intervals
beyond those specified for
unmonitored Components. (Part
1.2).
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
9
VRF and VSL Justifications – PRC‐005‐3, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
VSL Level Assignments Should
Ensure Uniformity and
Consistency in the
Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R1
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
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VRF and VSL Justifications – PRC‐005‐3, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance‐based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal‐performing Protection System
Components. Failure to properly establish a performance‐based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC‐008‐3 Requirement R2 and FAC‐013‐2 Requirement R1, which are similar in nature to
PRC‐005‐2 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance‐based Protection System Maintenance Program (PSMP) for.
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
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VRF and VSL Justifications – PRC‐005‐3, R2
Proposed VRF
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal‐performing Protection System
Components. Failure to properly establish a performance‐based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐3, R2
Lower
The responsible entity uses
performance‐based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance‐based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
The responsible entity uses
performance‐based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance‐based
PSMP
13
Proposed VSL – PRC‐005‐3, R2
Lower
Moderate
High
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a Segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the Segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
Segment.
14
VRF and VSL Justifications – PRC‐005‐3, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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15
VRF and VSL Justifications – PRC‐005‐3, R2
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
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16
VRF and VSL Justifications – PRC‐005‐3, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
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17
Proposed VSL – PRC‐005‐3, R3
Lower
Moderate
High
Severe
For Components included
within a time‐based
maintenance program, the
responsible entity failed to
maintain 5% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1‐1 through 1‐5, Table 2,
Table 3, and Table 4.
For Components included
within a time‐based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1‐1 through 1‐5, Table 2,
Table 3, and Table 4.
For Components included within a
time‐based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1‐1 through 1‐5,
Table 2, Table 3, and Table 4.
For Components included within a
time‐based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1‐1
through 1‐5, Table 2, Table 3, and
Table 4.
VRF and VSL Justifications
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VRF and VSL Justificati3ons – PRC‐005‐3, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R3
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
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21
Proposed VSL – PRC‐005‐3, R4
Lower
For Components included
within a performance‐based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Component Type
in accordance with their
performance‐based PSMP.
Moderate
For Components included
within a performance‐based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance‐based PSMP.
High
Severe
For Components included within a
performance‐based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance‐based PSMP.
For Components included within a
performance‐based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance‐based
PSMP.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R4
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from mal‐
performing Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only requirement within approved Standards, PRC‐004‐2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC‐022‐1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC‐003‐2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R5
Proposed VRF
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal‐performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐3, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
VRF and VSL Justifications
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
26
VRF and VSL Justifications – PRC‐005‐3, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The Requirement in PRC‐005‐2 has not been implemented; consequently, there is no prior level of
compliance.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC‐005‐3, R5
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
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28
Violation Risk Factor and Violation
Severity Level Justifications
Project 2007-17 –.2 PRC-005-23
Protection System and Automatic Reclosing Maintenance
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC‐005‐2 —‐ Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC‐approved Reliability Standards, as defined in the ERO Sanction Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors– VRFs
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning
time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to
hinder restoration to a normal condition.
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2
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk FactorVRF Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk FactorsVRFs assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical impact on
the reliability of the Bulk‐Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk‐Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub‐Requirement Violation Risk
FactorVRF assignments and the main Requirement Violation Risk FactorVRF assignment.
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Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk FactorsVRFs corresponding to
Requirements that address similar reliability goals in different Reliability Standards would be treated
comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk FactorVRF Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
FactorVRF level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co‐mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and
4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s
Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the requirements.
PRC‐005‐3 Protection System and Automatic Reclosing Maintenance is a revision of PRC‐005‐2
Protection System Maintenance is a revision of PRC‐005‐1a Transmission and Generation Protection
System Maintenance and Testing with the stated purpose: To document and implement programs
for the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) so that these Protection Systemsthey are kept in working order. PRC‐008‐
0 Implementation and Documentation of Underfrequency Load Shedding Equipment Maintenance
Program, PRC‐011‐0 Undervoltage Load Shedding System Maintenance and Testing and PRC‐017‐0
Special Protection System Maintenance and Testing are also being replaced by merging them into
PRC‐005‐2 in accordance with suggestions from FERC Order 693. PRC‐005‐2 also establishes
maximum allowable maintenance intervals as directed by FERC in Order 693 in their discussion of
the legacy standards PRC‐005‐1, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0.
PRC‐005‐23 has five (5) requirements that incorporate and enhance the intent of the requirements
of PRC‐005‐1a, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0. Several Tablesaddress the inclusion of
Automatic Reclosing. A Table of minimum maintenance activities and maximum maintenance
intervals are also includedhas been added to addressesPRC‐005‐2 to address FERC’s directives from
Order 693758. The revised standard requires that entities develop an appropriate Protection
System Maintenance Program (PSMP), that they implement their PSMP, and that, in the event they
are unable to restore Protection SystemAutomatic Reclosing Components to proper working order
while performing maintenance, they initiate the follow‐up activities necessary to resolve those
maintenance issues.
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4
The requirements of PRC‐005‐2 do not3 map, one‐to‐one, with the requirements of PRC‐005‐2. The
drafting team did not revise the legacy standards, each of which comingle various attributes
addressed within the new standard; thus, a requirement‐to‐requirement comparison of VRFs is
irrelevant. When developing VRFs for the requirements of PRC‐005‐2, the Standard Drafting Team
carefully considered the NERC criteria for developing VRFs, as well as the FERC VRF guidelines.
Therefore, PRC‐005‐2 Requirements R3 and R4 are assigned a VRF of High, while Requirements R1,
R2, and R5 are assigned VRFs of Medium3.
PRC‐005‐23 Requirements R1 and R2 are related to developing and documenting a Protection
System Maintenance Program. The Standard Drafting Team determined that the assignment of a
VRF of Medium was consistent with the NERC criteria that violations of these requirements could
directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system but are unlikely to lead to bulk electric
system instability, separation, or cascading failures. Additionally, a review of the body of existing
NERC Standards with approved VRFs revealed that requirements with similar reliability objectives in
other standards are largely assigned a VRF of Medium.
PRC‐005‐23 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC‐005‐23 Requirement R5 relates to the initiation of resolution of unresolved maintenance issues,
which describe situations where an entity was unable to restore a Component to proper working
order during the performance of the maintenance activity. The Standard Drafting Team determined
that the assignment of a VRF of Medium was consistent with the NERC criteria that violation of this
requirements could directly affect the electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric system but are unlikely to lead to bulk
electric system instability, separation, or cascading failures. Additionally, a review of the body of
existing NERC Standards with approved VRFs revealed that requirements with similar reliability
objectives in other standards are largely assigned a VRF of Medium.
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NERC Criteria - Violation Severity LevelsVSLs
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have at
least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
Violation severity levelsVSLs should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
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FERC Order on Violation Severity LevelsVSLs
In its June 19, 2008 Order on Violation Severity LevelsVSLs, FERC indicated it would use the following four guidelines for determining whether
to approve VSLs:
Guideline 1: Violation Severity LevelVSL Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior Levels of Non‐compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non‐compliance were used.
Guideline 2: Violation Severity LevelVSL Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity LevelVSL Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity LevelVSL Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of
Violations
. . . unless otherwise stated in the requirement, each instance of non‐compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
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VRF and VSL Justifications
VRF and VSL Justifications – PRC‐005‐23, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal‐performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no sub‐requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC‐008‐3 Requirement R2 and FAC‐013‐2 Requirement R1, which are similar in nature to PRC‐
005‐2 Requirement R1.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
8
VRF and VSL Justifications – PRC‐005‐23, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal‐performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF...
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐23, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time‐based or
performance‐based
maintenance, or a
combination of both. (Part 1.1)
OR
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time‐based or
performance‐based
maintenance, or a combination
of both. (Part 1.1)
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007‐17.2 – PRC‐005‐23: Protection System and Automatic Reclosing Maintenance
VRF and VSL Justifications | October 2012 | April 2013
High
Severe
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Protection Systemspecify
whether three Component Type
consistent with theTypes are
being addressed by time‐based or
performance‐based maintenance
intervals specified in Tables, or a
combination of both. (Part 1‐.1
through 1‐).
The responsible entity failed to
establish a PSMP.
OR
The responsible entityentity’s PSMP
failed to specify whether threefour
or more Component Types are
being addressed by time‐based or
performance‐based maintenance,
or a combination of both. (Part
1.1).
9
OR
Proposed VSL – PRC‐005‐23, R1
Lower
OR
The responsible entity’s PSMP
failed to include applicable
station batteries in a time‐
based program (Part 1.1)
Moderate
High
Severe
5, Table 2, and Table 3The
responsible entity’s PSMP failed
to include the applicable
monitoring attributes applied to
each Component Type consistent
with the maintenance intervals
specified in Tables 1‐1 through 1‐
5, Table 2, Table 3, and Table 4
where monitoring is used to
extend the maintenance intervals
beyond those specified for
unmonitored Protection System
Components. (Part 1.2).
addressed by time‐based or
performance‐based maintenance,
or a combination of both. (Part
1.1).
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
10
VRF and VSL Justifications – PRC‐005‐23, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity LevelVSL
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
Violation SeverityVSL Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity LevelVSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
LevelVSL Assignments that
Contain Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
11
VRF and VSL Justifications – PRC‐005‐23, R1
FERC VSL G3
Violation Severity LevelVSL
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity LevelVSL
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
12
VRF and VSL Justifications – PRC‐005‐23, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance‐based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal‐performing Protection System
Components. Failure to properly establish a performance‐based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC‐008‐3 Requirement R2 and FAC‐013‐2 Requirement R1, which are similar in nature to
PRC‐005‐2 Requirement R1.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance‐based Protection System Maintenance Program (PSMP) for .
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
13
VRF and VSL Justifications – PRC‐005‐23, R2
Proposed VRF
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal‐performing Protection System
Components. Failure to properly establish a performance‐based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐23, R2
Lower
The responsible entity uses
performance‐based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance‐based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
The responsible entity uses
performance‐based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance‐based
PSMP
14
Proposed VSL – PRC‐005‐3, R2
Lower
The responsible entity uses
performance‐based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance‐based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
OR
2)
The
responsible entity uses
performance‐based maintenance
intervals in its PSMP but:
1)Failed to establish the technical
justification describedreduce
countable events to no more than
4% within Requirement R2 for five
years
OR
3) Maintained a Segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the initial
usegreater of 5% of the
performance‐based PSMP
Segment population or 3
Components,
15
OR
• Annually analyze the program
activities and results for each
Segment.
VRF and VSL Justifications – PRC‐005‐3, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
16
Proposed VSL – PRC‐005‐2, R2
Lower
Moderate
High
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
segment.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
17
VRF and VSL Justifications – PRC‐005‐2, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
18
VRF and VSL Justifications – PRC‐005‐23, R2
Guideline 2b: Violation Severity
LevelVSL Assignments that
Contain Ambiguous Language
FERC VSL G3
Violation Severity LevelVSL
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity LevelVSL
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
19
VRF and VSL Justifications – PRC‐005‐23, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
20
Proposed VSL – PRC‐005‐23, R3
Lower
Moderate
High
Severe
For Protection System
Components included within a
time‐based maintenance
program, the responsible entity
failed to maintain 5% or less of
the total Components included
within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1‐1 through 1‐5, Table 2,
Table 3, and Table 34.
For Protection System
Components included within a
time‐based maintenance
program, the responsible entity
failed to maintain more than
5% but 10% or less of the total
Components included within a
specific Protection System
Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1‐1 through 1‐5, Table 2,
Table 3, and Table 34.
For Protection System
Components included within a
time‐based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Protection System Component
Type, in accordance with the
minimum maintenance activities
and maximum maintenance
intervals prescribed within Tables
1‐1 through 1‐5, Table 2, Table 3,
and Table 34.
For Protection System
Components included within a
time‐based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1‐1 through 1‐5,
Table 2, Table 3, and Table 34.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
21
VRF and VSL Justificati3ons – PRC‐005‐23, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity LevelVSL
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity LevelVSL
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity LevelVSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
LevelVSL Assignments that
Contain Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
22
VRF and VSL Justifications – PRC‐005‐23, R3
FERC VSL G3
Violation Severity LevelVSL
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity LevelVSL
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
23
VRF and VSL Justifications – PRC‐005‐23, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
24
Proposed VSL – PRC‐005‐23, R4
Lower
Moderate
For Protection System
Components included within a
performance‐based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Protection System
Component Type in accordance
with their performance‐based
PSMP.
For Protection System
Components included within a
performance‐based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance‐based
PSMP.
High
For Protection System
Components included within a
performance‐based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance‐based
PSMP.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
For Protection System
Components included within a
performance‐based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Protection System Component
Type in accordance with their
performance‐based PSMP.
25
VRF and VSL Justifications – PRC‐005‐23, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity LevelVSL
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
Violation Severity LevelVSL
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity LevelVSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
LevelVSL Assignments that
Contain Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
26
VRF and VSL Justifications – PRC‐005‐23, R4
FERC VSL G3
Violation Severity LevelVSL
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity LevelVSL
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
27
VRF and VSL Justifications – PRC‐005‐23, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from mal‐
performing Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1‐ Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2‐ Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3‐ Consistency among Reliability Standards:
The only requirement within approved Standards, PRC‐004‐2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC‐022‐1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC‐003‐2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
FERC VRF G4 Discussion
Guideline 4‐ Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
28
VRF and VSL Justifications – PRC‐005‐23, R5
Proposed VRF
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal‐performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5‐ Treatment of Requirements that Co‐mingle More than One Obligation:
This requirement establishes a single risk‐level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC‐005‐23, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
29
VRF and VSL Justifications – PRC‐005‐23, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
Violation Severity LevelVSL
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
This is a newThe Requirement in PRC‐005‐2 has not been implemented; consequently, there is no prior
level of compliance.
FERC VSL G2
Violation Severity LevelVSL
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity LevelVSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
LevelVSL Assignments that
Contain Ambiguous Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
30
VRF and VSL Justifications – PRC‐005‐23, R5
FERC VSL G3
Violation Severity LevelVSL
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity LevelVSL
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007‐17 – PRC‐005‐2: Protection System Maintenance
VRF and VSL JustificationsVRF and VSL Justifications | October 2012
Project 2007‐17.2 PRC‐005‐3: Protection System and Automatic Reclosing Maintenance | April 2013
31
``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
April 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ......................... 2
2.2 Protection System Definition ................................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ........................................ 3
2.3.1 Frequently Asked Questions: ............................................................................................. 4
2.4.1 Frequently Asked Questions: ............................................................................................. 6
3. Protection Systems Product Generations ................................................................................... 8
4. Definitions ................................................................................................................................. 10
4.1 Frequently Asked Questions: .............................................................................................. 11
5. Time‐Based Maintenance (TBM) Programs .............................................................................. 13
5.1 Maintenance Practices ....................................................................................................... 13
5.1.1 Frequently Asked Questions: ....................................................................................... 15
5.2 Extending Time‐Based Maintenance .............................................................................. 16
5.2.1 Frequently Asked Questions: ....................................................................................... 16
6. Condition‐Based Maintenance (CBM) Programs ...................................................................... 18
6.1 Frequently Asked Questions: .............................................................................................. 18
7. Time‐Based Versus Condition‐Based Maintenance .................................................................. 20
7.1 Frequently Asked Questions: .............................................................................................. 20
8. Maximum Allowable Verification Intervals............................................................................... 26
8.1 Maintenance Tests .............................................................................................................. 26
8.1.1 Table of Maximum Allowable Verification Intervals.................................................... 26
ii
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
8.1.2 Additional Notes for Tables 1‐1 through 1‐5 and Table 3 ........................................... 28
8.1.3 Frequently Asked Questions: ....................................................................................... 29
8.2 Retention of Records .......................................................................................................... 34
8.2.1 Frequently Asked Questions: ....................................................................................... 34
8.3 Basis for Table 1 Intervals ................................................................................................... 36
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 37
9. Performance‐Based Maintenance Process ............................................................................... 40
9.1 Minimum Sample Size......................................................................................................... 41
9.2 Frequently Asked Questions: .............................................................................................. 43
10. Overlapping the Verification of Sections of the Protection System ....................................... 54
10.1 Frequently Asked Questions: ............................................................................................ 54
11. Monitoring by Analysis of Fault Records ................................................................................ 55
11.1 Frequently Asked Questions: ............................................................................................ 56
12. Importance of Relay Settings in Maintenance Programs ....................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 57
13. Self‐Monitoring Capabilities and Limitations.......................................................................... 60
13.1 Frequently Asked Questions: ............................................................................................ 61
14. Notification of Protection System Failures ............................................................................. 62
15. Maintenance Activities ........................................................................................................... 63
15.1 Protective Relays (Table 1‐1) ............................................................................................ 63
15.1.1 Frequently Asked Questions: ..................................................................................... 63
15.2 Voltage & Current Sensing Devices (Table 1‐3) ............................................................ 63
15.2.1 Frequently Asked Questions: ..................................................................................... 65
15.3 Control circuitry associated with protective functions (Table 1‐5) .............................. 66
15.3.1 Frequently Asked Questions: ..................................................................................... 68
iii
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
15.4 Batteries and DC Supplies (Table 1‐4) ........................................................................... 70
15.4.1 Frequently Asked Questions: ..................................................................................... 70
15.5 Associated communications equipment (Table 1‐2) ........................................................ 84
15.5.1 Frequently Asked Questions: ..................................................................................... 86
15.6 Alarms (Table 2) ................................................................................................................ 89
15.6.1 Frequently Asked Questions: ..................................................................................... 89
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) ............................................... 90
15.7.1 Frequently Asked Questions: ..................................................................................... 90
15.8 Examples of Evidence of Compliance ............................................................................... 91
15.8.1 Frequently Asked Questions: ......................................................................................... 91
References .................................................................................................................................... 93
Figures ........................................................................................................................................... 95
Figure 1: Typical Transmission System ..................................................................................... 95
Figure 2: Typical Generation System ........................................................................................ 96
Figure 1 & 2 Legend – components of Protection Systems .......................................................... 97
Appendix A .................................................................................................................................... 98
Appendix B .................................................................................................................................. 101
Protection System Maintenance Standard Drafting Team ......................................................... 101
iv
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
1. Introduction and Summary
Note: This supplementary reference for PRC‐005‐3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC‐005‐1b — Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC‐011‐0 — UVLS System Maintenance and Testing
PRC‐017‐0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs. Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC‐005‐3 will replace
PRC‐005‐2 which combined and replaced PRC‐005, PRC‐008, PRC‐011 and PRC‐017. PRC‐005‐3
adds Automatic Reclosing to PRC‐005‐2.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation ‐ a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed ‐ can result
in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC‐005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC‐005‐3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC‐005‐2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
Protective relays which respond to electrical quantities,
Communications systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC‐005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in‐force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non‐transmission voltage level (Distribution
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 would
apply to this equipment. An example is underfrequency load‐shedding, which is frequently
applied well down into the distribution system to meet PRC‐007‐0.
PRC‐005‐2 replaced the existing PRC‐005, PRC‐008, PRC‐011 and PRC‐017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC‐008 was
constructed quite differently than the original PRC‐005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock‐out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC‐005‐2 replaced PRC‐011, it will be important to make the distinction
between under‐voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC‐011 is now applicable under PRC‐005‐2. An example of an under‐voltage
load‐shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC‐011 are the very same types of
devices needed in PRC‐005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
4
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non‐transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 applies to this
equipment. An example is underfrequency load‐shedding, which is frequently applied well
down into the distribution system to meet PRC‐007‐0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock‐out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non‐BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip‐test requirements. For these devices that are otherwise non‐BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock‐out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC‐005‐2, the drafting team combined legacy standards PRC‐005‐1b, PRC‐008‐
0, PRC‐011‐0, and PRC‐017‐0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
5
The intent of the drafting team is that the legacy standards be reflected in PRC‐005‐2 as
follows:
Applicability of PRC‐005‐1b for Protection Systems relating to non‐generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC‐008‐0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC‐011‐0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC‐017‐0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC‐005‐1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage‐sensing devices.
Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC‐005‐3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Applied on BES Elements at generating plant substations where the total
installed generating plant capacity is greater than the capacity of the largest
generating unit within the Balancing Authority Area.
4.2.6.2 Applied on BES Elements at substations one bus away from generating plants
specified in Section 4.2.6.1 when the substation is less than 10 circuit‐miles from
the generating plant substation.
4.2.6.3 Applied as an integral part of a SPS specified in Section 4.2.4.
Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
6
a close‐in three‐phase fault present for twice the normal clearing time (capturing a minimum
trip‐close‐trip time delay) does not result in a total loss of generation in the Interconnection
exceeding the largest unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal‐performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when inadvertent reclosing
near a generating station subjects the generation station to severe fault stresses. A technical
report, “Considerations for Maintenance and Testing of Autoreclosing Schemes — November
2012”, is referenced in PRC‐005‐3 and provides a more detailed discussion of these concerns.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the low‐
voltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low‐voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2‐2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is unaware
of industry‐recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
7
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non‐electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2‐2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock‐out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
8
3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor‐based relays have six significant traits that impact a maintenance
strategy:
Self monitoring capability ‐ the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non‐Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current‐measuring devices, and even the control
circuitry (in the form of software‐latches replacing lock‐out relays, etc.).
Any Protection System component can have self‐monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand‐held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessor‐
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
9
based device that results in a “lock‐out.” Thus, the software‐latch 86 that replaces an electro‐
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
10
4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and Automatic Reclosing Components are kept in working order and proper operation
of malfunctioning components is restored. A maintenance program for a specific component
includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in‐service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Reclosing relay
Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti‐pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow‐up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three‐phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Misoperation attributed to hardware failure or calibration
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
11
failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC‐005‐1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC‐005‐3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1‐1 through 1‐5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC‐005‐3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid‐state protective
relays to microprocessor‐based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance‐time‐interval‐clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time‐interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
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management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed‐end process”).
For example, a problem might be identified on a VRLA battery during a six‐month check. In
instances such as one that requiring battery replacement as part of the long‐term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six‐calendar‐month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time‐based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location ‐ for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on‐command or routinely;
the running of these tests can extend the time interval between hands‐on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
TBM – time‐based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
PBM – Performance‐Based Maintenance ‐ intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM‐
developed extended intervals when test failures or in‐service failures occur infrequently.
CBM – condition‐based maintenance – continuously or frequently reported results from
non‐disruptive self‐monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self‐diagnostics. While the term “Condition‐Based‐
Maintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status‐monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored‐basis‐time‐intervals” existing within the standard, the
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explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor‐based Protection System or Automatic Reclosing Components that
perform continuous self‐monitoring verify correct operation of most components within
the device. Self‐monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self‐monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with self‐
monitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non‐disruptive self‐monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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TBM
1
2
3
CBM
PBM
Relationship of time‐based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition‐based Maintenance (R1) and
Performance‐Based Maintenance (R2), in addition to simple time‐based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time‐based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance‐Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off-line by tripping the
transformer’s high-side and low-side circuit breakers. What testing must be done
for this system?
This system is made up of components that are all unmonitored. Assuming a time‐based
Protection System Maintenance Program schedule (as opposed to a Performance‐Based
maintenance program), each component must be maintained per the most frequent hands‐on
activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time‐based. Default time‐based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from time‐
based maintenance. The following factors may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self‐monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition‐based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor‐based relays, self‐monitoring may not include automated
diagnostics of every component within a microprocessor.
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Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance‐Based Maintenance, or
PBM. It is also sometimes referred to as reliability‐centered maintenance, or RCM; but
PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor‐based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition‐based maintenance is the process of gathering and monitoring the information
available from modern microprocessor‐based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self‐monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non‐invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
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provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1‐4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device‐level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1‐4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1‐4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7. Time-Based Versus Condition-Based
Maintenance
Time‐based and condition‐based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time‐based and condition‐based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06‐16‐000) on Mandatory Reliability Standards
for the Bulk‐Power System, directed NERC to submit a modification to PRC‐005‐1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC‐005‐3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition‐based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous ‐ the time interval between verifications is
minutes or seconds. Thus, technically sound, condition‐based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time‐based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on‐site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC‐005‐3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four‐month
inspection was performed in January is due in May, but if performed in March (instead of May)
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would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with an internal alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented Lead‐Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1‐5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead‐acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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Vented Lead‐Acid battery without any alarms connected to SCADA
(unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition‐Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely ‐ for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters ‐ this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1‐1 through 1‐5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications‐assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub‐systems of a Protection System that need to be verified are shown.
Non‐distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non‐distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co‐located non‐BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC‐005‐3:
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First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1‐1 is for protective relays,
o Table 1‐2 is for the associated communications systems,
o Table 1‐3 is for current and voltage sensing devices,
o Table 1‐4 is for station dc supply and
o Table 1‐5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make‐up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
Next look within that table for your device and its degree of monitoring. The Tables
have different hands‐on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
This Maintenance activity is the minimum maintenance activity that must be
documented.
If your Performance‐Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands‐on maintenance activity cycles of
this component.
If your Performance‐Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands‐on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
An entity does not have to utilize the extended time intervals made available by this use
of condition‐based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance man‐
hours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC‐005‐3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC‐005‐3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance‐Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead‐acid,
valve‐regulated lead‐acid, and nickel‐cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC‐005‐3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC‐005‐3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
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properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End‐to‐end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications‐assisted trip scheme. While
this can be interpreted as a GPS‐type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally‐test the dc control circuitry. A documented Real‐time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real‐time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1‐8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology‐ and method‐neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor‐ based relays.
For relay maintenance departments that choose to test microprocessor‐based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor‐ based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time‐overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end‐to‐end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real‐time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not‐to‐exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four‐month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time‐based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance‐Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
Fault protective functions, including distance functions, voltage‐restrained overcurrent
functions, or voltage‐controlled overcurrent functions
Loss‐of‐field relays
Volts‐per‐hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator‐ground relays
Communications‐based Protection Systems such as transfer‐trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out‐of‐step relays
Inadvertent energization protection
Breaker failure protection
For generator step‐up, generator‐connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
Transformer differential relays
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Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal‐conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system‐connected station service transformers be included in
the Applicability. The generator‐connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock‐out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non‐distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non‐distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC‐005‐1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three‐year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC‐005‐3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on‐site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance‐Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance‐time‐interval‐
clock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time‐interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
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The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC‐005‐3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged‐Fault‐tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be re‐
verified within an ongoing maintenance program. Example – it is not necessary to re‐verify
correct terminal strip wiring on an ongoing basis.
PRC‐005‐3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC‐005‐3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC‐005‐3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
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It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non‐compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in‐service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in‐service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1‐1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto‐generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built‐in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I‐17 (Transmission Relay System
Performance Comparison). Review of the I‐17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
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To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively‐known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self‐testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1‐1 through 1‐5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10‐year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self‐monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
Relay Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
Abnormal Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self‐monitoring capability is ST (for self test).
ST = 0 if there is no self‐monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
38
Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time‐interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “time‐
interval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time‐interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six‐year interval for the
electromechanical relay, instead of the five‐year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10‐year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
39
facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance‐Based Maintenance process may be used to
establish maintenance intervals (PRC‐005 Attachment A Criteria for a Performance‐Based
Protection System Maintenance Program). A Performance‐Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance‐Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance‐Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance‐Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance‐Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001‐2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance‐Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro‐mechanical lock‐out relays;
likewise, one segment cannot be comprised of 60 GE lock‐out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics ‐ Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis ‐ Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
42
2
z
n 1
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance‐Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance‐Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1‐1 through 1‐5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4%Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
to the requirements of the Standard. The requirements established for Performance‐Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power‐plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance‐Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance‐Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance‐Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in‐service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re‐calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human‐error is not pertinent data might be in the area of testing “86” lock‐out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial six‐
year interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human‐error caused tripping
incidents. In this example the human‐error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal‐performing segments in a Performance‐Based Maintenance system. Some examples are
listed below.
The maximum allowable interval, as established by the Performance‐Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
Identifiable sub‐groups of components within the established segment, which have
been identified to be the mal‐performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance‐Based Maintenance program in
order to remain within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal‐performance.
components within the mal‐performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal‐performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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If you perform maintenance on a Protection System component for any reason (including as
part of a PRC‐004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance‐Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance‐Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock‐reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1‐1‐11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6‐1‐12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock‐reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance‐Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance‐changing criteria.
Similarly, Functional Entities that want to establish a condition‐based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands‐on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1‐4).
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE‐HEA lock‐out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
47
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six‐year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
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Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V‐insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper‐sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
49
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real‐time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12‐
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
50
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested / year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
51
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off‐line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real‐time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built‐in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity‐accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
52
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note ‐ a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
53
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
54
10. Overlapping the Verification of Sections of the
Protection System
Tables 1‐1 through 1‐5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
Time‐based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1‐1 through 1‐5;
Monitoring as described in Tables 1‐1 through 1‐5;
A Performance‐Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto‐polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
55
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time‐interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance‐related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
56
11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC‐018‐1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC‐002‐1 and PRC‐018‐1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
57
12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single self‐
monitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non‐microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
58
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenance‐
activity‐time‐interval‐clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up‐rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC‐005‐3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC‐005‐3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC‐005‐3 to remove
such component(s). Obviously, prudence would dictate that an “out‐of‐service” device is truly
made inactive. There are no record requirements listed in PRC‐005‐3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC‐005‐3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC‐005‐3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
59
The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
60
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self‐monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self‐monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands‐on
maintenance requirement), the manufacturers of the microprocessor‐based self‐monitoring
components in the Protection System should publish for the user a document or map that
shows:
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
61
13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology‐neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
62
14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early‐generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
63
15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC‐005‐3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non‐electrical inputs are excluded.
Non‐microprocessor based equipment is treated differently than microprocessor‐based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
Non‐microprocessor devices must be tested with voltage and/or current applied to the
device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber‐optic Hall‐effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
64
protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real‐time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
Another method for proving the voltage and/or current‐sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current‐sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all‐inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi‐meters, voltmeter, clamp‐on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re‐check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi‐pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt‐meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual‐intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This six‐
year tripping requirement can be completed as easily as tracking the Real‐time Fault‐clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit‐interrupting device should not be confused with a motor‐operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high‐speed auto‐closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred‐tripping
device without the use of communications equipment. If this high‐speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring‐operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock‐out relay
(86) that may exist in any particular trip scheme. If the lock‐out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six‐year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non‐BES interrupting devices are not required. Normally‐open contacts
that are not used to pass a trip signal and normally‐closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC‐005‐2, other alarming relay control circuits,
(i.e., SF‐6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard‐wired trip circuitry with other methods of trip‐signal conveyance
such as fiber‐optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber‐optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is
unaware of industry‐recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐
17, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC‐005‐3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC‐005‐3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1‐5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC‐005‐3 includes high‐speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non‐BES circuit breaker that is tripped via a Protection
System to which PRC‐005‐3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non‐black‐start) radial Loads but has a trip that originates from an under‐frequency
(81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non‐BES breaker that is tripped via a Protection
System to which PRC‐005‐3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non‐black‐start) radial Loads but has a trip that originates from a BES 115KV
line relay.
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock‐out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock‐out (86) (or auxiliary (94)) relay and the
non‐BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non‐BES circuit breaker that is tripped via a
Protection System to which PRC‐005‐3 applies, such as the generator field breaker and low‐side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non‐BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
The differential relay must be verified.
The current signals to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally‐closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
Protective relays which respond to electrical quantities,
Communications Systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1‐4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance‐Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance‐changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC‐005‐3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger ‐ The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery ‐ Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1‐4.
Emerging Technologies ‐ Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1‐4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1‐4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor‐based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one‐ to two‐
second delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp‐range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc‐supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor‐controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
Internal ohmic measurements of the cells and units of lead‐acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1‐4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve‐regulated lead‐acid, vented
lead‐acid, or nickel‐cadmium) and the maintenance activity chosen.
For example, if you have a valve‐regulated lead‐acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the six‐
month interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead‐acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six‐months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve‐regulated lead‐acid (VRLA) batteries and vented lead‐acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer‐supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead‐acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel‐cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve‐regulated lead‐acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1‐4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell‐to‐cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1‐4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1‐4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell‐to‐cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1‐4 by a Performance‐Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1‐4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1‐4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot‐checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally‐accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel‐cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel‐cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel‐cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel‐cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel‐cadmium batteries,
there are no significantly measurable properties of the nickel‐cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1‐4(c)
(Protection System Station dc supply Using nickel‐cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check‐off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check‐off per battery bank is sufficient for documentation, as long as the single check‐
off attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC‐005‐3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve‐Regulated Lead‐Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead‐Acid (VLA)
batteries were unable to be used on this new type of lead‐acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188‐2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1‐4. In cases where individual cells in a multi‐cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1‐4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead‐acid (VLA) and nickel‐cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1‐4. Because
the electrolyte level in valve‐regulated lead‐acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1‐4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved‐quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve‐regulated lead‐acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1‐4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead‐acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry‐out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1‐4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six‐month test” at Row 4 on Table 1‐4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1‐4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six‐month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline ‐ others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six‐month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1‐4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self‐
monitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1‐4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1‐4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1‐4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1‐4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1‐4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1‐4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1‐4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications‐assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications‐assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communications‐
assisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber‐optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on‐site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
On‐off power‐line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check‐back test from one terminal.
Systems which use frequency‐shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss‐of‐guard indication or alarm. For frequency‐shift power‐line carrier systems, the
guard signal level meter can also be checked.
Hard‐wired pilot wire line Protection Systems typically have pilot‐wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
On‐off power‐line carrier systems can be shown to be operational by automated
periodic power‐line carrier check‐back tests with remote alarming of failures.
Systems which use a frequency‐shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss‐of‐guard alarm or low signal level alarm.
Hard‐wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot‐wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements, including signal‐to‐noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four‐month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
Power Line Carrier (PLC) ‐ The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical‐electrical signal format converters are the associated
communications equipment
Figure 1‐2, A‐1 and A‐2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
An on‐off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check‐back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre‐determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1‐1 through 1‐5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto‐polling system; the only
requirement is that the alarm be brought to the action‐site within 24 hours. This effectively
makes manned‐stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned‐station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non‐manned‐
station, which is that if the monitored point has an alarm that is auto‐reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail‐safe “form‐b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1‐1. Voltage and current‐sensing devices have the same maintenance activity and
interval as Table 1‐3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
Verify the trip path between the relay and lock‐out and/or auxiliary tripping device(s).
Verify operation of any lock‐out and/or auxiliary tripping device(s) used in the trip
circuit.
No verification of trip path required between the lock‐out (and/or auxiliary tripping
device) and the non‐BES interrupting device.
No verification of trip path required between the relay and trip coil for circuits that have
no lock‐out and/or auxiliary tripping device(s).
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non‐BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load‐Shed relay and lock‐out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock‐out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under‐frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non‐BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock‐out relay. While many failures of these distributed system circuit breakers (or
non‐BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non‐BES device, such as a battery bank that serves both a BES circuit breaker and a non‐BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during under‐
frequency or under‐voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load‐generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC‐005‐3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC‐005‐3.
15.8.1 Frequently-asked Questions
None
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team
recognizes that there are concurrent evidence requirements of other NERC standards that
could, at times, fulfill evidence requirements of this Standard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check‐off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
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If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC‐016 could work for the activity tracking requirements
under this PRC‐005‐3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
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References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor‐Based
Transmission‐Line Protective Relays, Part I ‐ Explanation of the Statistics, and Part II ‐
Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016‐6
PWRD and 96WM 127‐1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR‐ 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve‐
Regulated Lead‐Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead‐Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45‐2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented Lead‐
Acid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR‐100248, 1006757, August 2002.
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
94
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” ‐ Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC‐005‐2, and also
may not be all‐inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Component of
Protection System
Includes
Excludes
Devices that use non‐electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync‐check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber‐optic systems that
carry a trip signal as well as hard‐
wired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
Tele‐protection equipment used
Communications
to convey specific information, in
systems necessary
the form of analog or digital
for correct operation
signals, necessary for the correct
of protective
operation of protective functions.
functions
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
4
5
Additional information can be found in References
PRC‐005‐3 Supplementary Reference and FAQ – April 2013
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Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A‐1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two‐terminal pilot protection scheme to protect for line Faults, and to avoid over‐
tripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self‐monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self‐monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
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5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on‐off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check‐back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A‐2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
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contacts of a small telephone‐type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check‐back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone‐type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally‐occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC‐005‐3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front‐panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay‐carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle Ashton
Tri‐State G&T
Bob Bentert
Florida Power & Light Company
Forrest Brock
Western Farmers Electric Cooperative
Aaron Feathers
Pacific Gas and Electric Company
Sam Francis
Oncor Electric Delivery
Carol Gerou
Midwest Reliability Organization
Russell C. Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
James M. Kinney
FirstEnergy Corporation
Mark Lucas
ComEd
Kristina Marriott
ENOSERV
Al McMeekin
NERC
Michael Palusso
Southern California Edison
Mark Peterson
Great River Energy
John Schecter
American Electric Power
William D. Shultz
Southern Company Generation
Eric A. Udren
Quanta Technology
Scott Vaughan
City of Roseville Electric Department
Matthew Westrich
American Transmission Company
Philip B. Winston
Southern Company Transmission
David Youngblood
Luminant Power
John A. Zipp
ITC Holdings
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``
Supplementary Reference
and FAQ
PRC-005-2 3 Protection System Maintenance
October 2012April 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ......................... 2
2.2 Protection System Definition ................................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ........................................ 3
2.3.1 Frequently Asked Questions: ............................................................................................. 4
2.4.1 Frequently Asked Questions: ............................................................................................. 6
3. Protection Systems Product Generations ................................................................................... 8
4. Definitions ................................................................................................................................. 10
4.1 Frequently Asked Questions: .............................................................................................. 11
5. Time‐Based Maintenance (TBM) Programs .............................................................................. 13
5.1 Maintenance Practices ....................................................................................................... 13
5.1.1 Frequently Asked Questions: ....................................................................................... 15
5.2 Extending Time‐Based Maintenance .............................................................................. 16
5.2.1 Frequently Asked Questions: ....................................................................................... 16
6. Condition‐Based Maintenance (CBM) Programs ...................................................................... 18
6.1 Frequently Asked Questions: .............................................................................................. 18
7. Time‐Based Versus Condition‐Based Maintenance .................................................................. 20
7.1 Frequently Asked Questions: .............................................................................................. 20
8. Maximum Allowable Verification Intervals............................................................................... 26
8.1 Maintenance Tests .............................................................................................................. 26
8.1.1 Table of Maximum Allowable Verification Intervals.................................................... 26
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8.1.2 Additional Notes for Tables 1‐1 through 1‐5 and Table 3 ........................................... 28
8.1.3 Frequently Asked Questions: ....................................................................................... 29
8.2 Retention of Records .......................................................................................................... 34
8.2.1 Frequently Asked Questions: ....................................................................................... 34
8.3 Basis for Table 1 Intervals ................................................................................................... 36
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 37
9. Performance‐Based Maintenance Process ............................................................................... 40
9.1 Minimum Sample Size......................................................................................................... 41
9.2 Frequently Asked Questions: .............................................................................................. 43
10. Overlapping the Verification of Sections of the Protection System ....................................... 54
10.1 Frequently Asked Questions: ............................................................................................ 54
11. Monitoring by Analysis of Fault Records ................................................................................ 55
11.1 Frequently Asked Questions: ............................................................................................ 56
12. Importance of Relay Settings in Maintenance Programs ....................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 57
13. Self‐Monitoring Capabilities and Limitations.......................................................................... 60
13.1 Frequently Asked Questions: ............................................................................................ 61
14. Notification of Protection System Failures ............................................................................. 62
15. Maintenance Activities ........................................................................................................... 63
15.1 Protective Relays (Table 1‐1) ............................................................................................ 63
15.1.1 Frequently Asked Questions: ..................................................................................... 63
15.2 Voltage & Current Sensing Devices (Table 1‐3) ............................................................ 63
15.2.1 Frequently Asked Questions: ..................................................................................... 65
15.3 Control circuitry associated with protective functions (Table 1‐5) .............................. 66
15.3.1 Frequently Asked Questions: ..................................................................................... 68
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15.4 Batteries and DC Supplies (Table 1‐4) ........................................................................... 70
15.4.1 Frequently Asked Questions: ..................................................................................... 70
15.5 Associated communications equipment (Table 1‐2) ........................................................ 84
15.5.1 Frequently Asked Questions: ..................................................................................... 86
15.6 Alarms (Table 2) ................................................................................................................ 89
15.6.1 Frequently Asked Questions: ..................................................................................... 89
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) ............................................... 90
15.7.1 Frequently Asked Questions: ..................................................................................... 90
15.8 Examples of Evidence of Compliance ............................................................................... 91
15.8.1 Frequently Asked Questions: ......................................................................................... 91
References .................................................................................................................................... 93
Figures ........................................................................................................................................... 95
Figure 1: Typical Transmission System ..................................................................................... 95
Figure 2: Typical Generation System ........................................................................................ 96
Figure 1 & 2 Legend – components of Protection Systems .......................................................... 97
Appendix A .................................................................................................................................... 98
Appendix B .................................................................................................................................. 101
Protection System Maintenance Standard Drafting Team ......................................................... 101
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1. Introduction and Summary
Note: This supplementary reference for PRC‐005‐2 3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC‐005‐1b — Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC‐011‐0 — UVLS System Maintenance and Testing
PRC‐017‐0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs. Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC‐005‐2 3 will replace
and PRC‐005‐32 which combineds and replaceds PRC‐005, PRC‐008, PRC‐011 and PRC‐017.
PRC‐005‐3 adds Automatic Reclosing to PRC‐005‐2.
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2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation ‐ a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed ‐ can result
in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC‐005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC‐005‐1 3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC‐005‐2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
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Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
Protective relays which respond to electrical quantities,
Communications systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC‐005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in‐force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non‐transmission voltage level (Distribution
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Provider equipment) that is wholly or partially installed to protect the BES. PRC‐005‐2 3 would
apply to this equipment. An example is underfrequency load‐shedding, which is frequently
applied well down into the distribution system to meet PRC‐007‐0.
As this standardPRC‐005‐2 is intended to replaced the existing PRC‐005, PRC‐008, PRC‐011 and
PRC‐017, those standards are used in the construction of this revision of PRC‐005‐1. Much of
the original intent of those standards was carried forward whenever it was possible to continue
the intent without a disagreement with FERC Order 693. For example, the original PRC‐008 was
constructed quite differently than the original PRC‐005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock‐out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since this standardPRC‐005‐2 will now replacereplacesd PRC‐011, it will be
important to make the distinction between under‐voltage Protection Systems that protect
individual Loads and Protection Systems that are UVLS schemes that protect the BES. Any UVLS
scheme that had been applicable under PRC‐011 will is now be applicable under this revision of
PRC‐005‐1PRC‐005‐2. An example of an under‐voltage load‐shedding scheme that is not
applicable to this standard is one in which the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission system that was intact except for the
line that was out of service, as opposed to preventing a Cascading outage or Transmission
system collapse.
It had been correctly noted that the devices needed for PRC‐011 are the very same types of
devices needed in PRC‐005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
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Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non‐transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC‐005‐2 3 would appliesy
to this equipment. An example is underfrequency load‐shedding, which is frequently applied
well down into the distribution system to meet PRC‐007‐0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock‐out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non‐BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip‐test requirements. For these devices that are otherwise non‐BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock‐out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC‐005‐2, the drafting team has combined legacy standards PRC‐005‐1b, PRC‐
008‐0, PRC‐011‐0, and PRC‐017‐0. The merger of the subject matter of these standards is
reflected in Applicability 4.2.
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The intent of the drafting team is that the legacy standards be reflected in PRC‐005‐2 as
follows:
Applicability of PRC‐005‐1b for Protection Systems relating to non‐generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC‐008‐0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC‐011‐0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC‐017‐0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC‐005‐1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage‐sensing devices.
Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC‐005‐3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
No. This standard covers protective relays that use electrical quantity measurements to
determine anomalies and to trip a portion of the BES. Reclosers, reclosing relays, closing
circuits and auto‐restoration schemes are used to cause devices to close, as opposed to
electrical‐measurement relays and their associated circuits that cause circuit interruption from
the BES; such closing devices and schemes are more appropriately covered under other NERC
standards. There is one notable exception: Since PRC‐017 will be superseded by PRC‐005‐2,
then if a Special Protection System (previously covered by PRC‐017) incorporates automatic
closing of breakers, then the SPS‐related closing devices must be tested accordingly.Yes.
Automatic Reclosing includes reclosing relays and the associated dc control circuitry. Section
4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Applied on BES Elements at generating plant substations where the total
installed generating plant capacity is greater than the capacity of the largest
generating unit within the Balancing Authority Area.
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4.2.6.2 Applied on BES Elements at substations one bus away from generating plants
specified in Section 4.2.6.1 when the substation is less than 10 circuit‐miles from
the generating plant substation.
4.2.6.3 Applied as an integral part of a SPS specified in Section 4.2.4.
Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
a close‐in three‐phase fault present for twice the normal clearing time (capturing a minimum
trip‐close‐trip time delay) does not result in a total loss of generation in the Interconnection
exceeding the largest unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal‐performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when inadvertent reclosing
near a generating station subjects the generation station to severe fault stresses. A technical
report, “Considerations for Maintenance and Testing of Autoreclosing Schemes — November
2012”, is referenced in PRC‐005‐3 and provides a more detailed discussion of these concerns.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the low‐
voltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low‐voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2‐2008 assigns the Device No.# 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No.# 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC‐005‐2 3 testing requirements because the SDT is unaware
of industry‐recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
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with the currently‐approved PRC‐005‐1a1b, consistent with the SAR for Project 2007‐17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non‐electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No.# 94, is described in IEEE Standard C37.2‐2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock‐out relay, IEEE Device No.# 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
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3. Protection System and Automatic Reclosings
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depends on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor‐based relays have six significant traits that impact a maintenance
strategy:
Self monitoring capability ‐ the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non‐Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current‐measuring devices, and even the control
circuitry (in the form of software‐latches replacing lock‐out relays, etc.).
Any Protection System component can have self‐monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand‐held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessor‐
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based device that results in a “lock‐out.” Thus, the software‐latch 86 that replaces an electro‐
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and Automatic Reclosing components Components are kept in working order and
proper operation of malfunctioning components is restored. A maintenance program for a
specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in‐service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Reclosing relay
Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti‐pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow‐up corrective action.
Segment – Protection Systems or cComponents of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a Segment. A Segment
must contain at least sixty (60) individual components.
Component Type ‐– Either aAny one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three‐phase set of such
devices or a single device as a single Component.*
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, and Table 3, and Table 4
which requires corrective action or a Misoperation attributed to hardware failure or calibration
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failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors, or Protection System application errors are not included in Countable
Events.
4.1 Frequently Asked Questions:
Why does PRC-005-2 3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC‐005‐1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC‐005‐2 3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1‐1 through 1‐5, Table 2, and Table 3, and Table 4 (collectively the
“Tables”), and the various components of the definition established for a “Protection System
Maintenance Program,” PRC‐005‐2 3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid‐state protective
relays to microprocessor‐based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance‐time‐interval‐clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time‐interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
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Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed‐end process”).
For example, a problem might be identified on a VRLA battery during a six‐month check. In
instances such as one that requiring battery replacement as part of the long‐term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six‐calendar‐month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time‐based maintenance is the process in which Protection Systems and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location ‐ for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
components Components can have the ability to remotely conduct tests, either on‐command or
routinely; the running of these tests can extend the time interval between hands‐on
maintenance activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
TBM – time‐based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
PBM – Performance‐Based Maintenance ‐ intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM‐
developed extended intervals when test failures or in‐service failures occur infrequently.
CBM – condition‐based maintenance – continuously or frequently reported results from
non‐disruptive self‐monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self‐diagnostics. While the term “Condition‐Based‐
Maintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status‐monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored‐basis‐time‐intervals” existing within the standard, the
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor‐based Protection System or Automatic Reclosing components
Components that perform continuous self‐monitoring verify correct operation of most
components within the device. Self‐monitoring capabilities may include battery
continuity, float voltages, unintentional grounds, the ac signal inputs to a relay, analog
measuring circuits, processors and memory for measurement, protection, and data
communications, trip circuit monitoring, and protection or data communications signals
(and many, many more measurements). For those conditions, failure of a self‐
monitoring routine generates an alarm and may inhibit operation to avoid false trips.
When internal components, such as critical output relay contacts, are not equipped with
self‐monitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non‐disruptive self‐monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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TBM
1
2
3
CBM
PBM
Relationship of time‐based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition‐based Maintenance (R1) and
Performance‐Based Maintenance (R2), in addition to simple time‐based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time‐based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance‐Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off-line by tripping the
transformer’s high-side and low-side circuit breakers. What testing must be done
for this system?
This system is made up of components that are all unmonitored. Assuming a time‐based
Protection System maintenance Maintenance program Program schedule (as opposed to a
Performance‐Based maintenance program), each component must be maintained per the most
frequent hands‐on activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time‐based. Default time‐based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from time‐
based maintenance. The following factors may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self‐monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition‐based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor‐based relays, self‐monitoring may not include automated
diagnostics of every component within a microprocessor.
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Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance‐Based Maintenance, or
PBM. It is also sometimes referred to as reliability‐centered maintenance, or RCM; but
PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor‐based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition‐based maintenance is the process of gathering and monitoring the information
available from modern microprocessor‐based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self‐monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non‐invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
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provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1‐4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device‐level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1‐4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1‐4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7. Time-Based Versus Condition-Based
Maintenance
Time‐based and condition‐based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time‐based and condition‐based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06‐16‐000) on Mandatory Reliability Standards
for the Bulk‐Power System, directed NERC to submit a modification to PRC‐005‐1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC‐005‐23. The defined time
limits allow for longer time intervals if the maintained component is monitored.
A key feature of condition‐based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous ‐ the time interval between verifications is
minutes or seconds. Thus, technically sound, condition‐based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time‐based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection Systems and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on‐site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables 1‐1 through 1‐5 and Table 2 of PRC‐005‐23.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four‐month
inspection was performed in January is due in May, but if performed in March (instead of May)
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would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with an internal alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented Lead‐Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1‐5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead‐acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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Vented Lead‐Acid battery without any alarms connected to SCADA
(unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition‐Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection Systems or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely ‐ for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters ‐ this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1‐1 through 1‐5), Table
2, and Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise Protection Systemsthese systems. The right column indicates
maintenance activities required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications‐assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub‐systems of a Protection System that need to be verified are shown.
Non‐distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non‐distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co‐located non‐BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC‐005‐23:
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1‐1 is for protective relays,
o Table 1‐2 is for the associated communications systems,
o Table 1‐3 is for current and voltage sensing devices,
o Table 1‐4 is for station dc supply and
o Table 1‐5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make‐up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
Next look within that table for your device and its degree of monitoring. The Tables
have different hands‐on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
This Maintenance activity is the minimum maintenance activity that must be
documented.
If your Performance‐Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands‐on maintenance activity cycles of
this component.
If your Performance‐Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands‐on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
An entity does not have to utilize the extended time intervals made available by this use
of condition‐based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available on in each of the five Tables. While
the maintenance activities resulting from this choice would require more maintenance
man‐hours, the maintenance requirements may be simpler to document and the
resulting maintenance plans may be easier to create.
For each Protection System componentComponent, Table 1 shows maximum allowable testing
intervals for the various degrees of monitoring. For each Automatic Reclosing Component,
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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Table 4 shows maximum allowable testing intervals for the various degrees of monitoring.
These degrees of monitoring, or levels, range from the legacy unmonitored through a system
that is more comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC‐005‐23.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC‐005‐23, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance‐Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5 and , Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead‐acid,
valve‐regulated lead‐acid, and nickel‐cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC‐005‐2 3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC‐005‐2 3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
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properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End‐to‐end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications‐assisted trip scheme. While
this can be interpreted as a GPS‐type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally‐test the dc control circuitry. A documented Real‐time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real‐time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1‐8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology‐ and method‐neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor‐ based relays.
For relay maintenance departments that choose to test microprocessor‐based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor‐ based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time‐overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end‐to‐end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real‐time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not‐to‐exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four‐month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time‐based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance‐Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
Fault protective functions, including distance functions, voltage‐restrained overcurrent
functions, or voltage‐controlled overcurrent functions
Loss‐of‐field relays
Volts‐per‐hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator‐ground relays
Communications‐based Protection Systems such as transfer‐trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out‐of‐step relays
Inadvertent energization protection
Breaker failure protection
For generator step‐up, generator‐connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
Transformer differential relays
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Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal‐conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system‐connected station service transformers be included in
the Applicability. The generator‐connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock‐out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
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distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non‐distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non‐distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC‐005‐1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three‐year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC‐005‐2 3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on‐site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance‐Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance‐time‐interval‐
clock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time‐interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
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The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC‐005‐23, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged‐Fault‐tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be re‐
verified within an ongoing maintenance program. Example – it is not necessary to re‐verify
correct terminal strip wiring on an ongoing basis.
PRC‐005‐2 3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC‐005‐2 3 requires performance of maintenance activities
that are deemed necessary to detect and correct plausible age and service related degradation
of components, such that a properly built and commission tested Protection System will
continue to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC‐005‐2 3 would help that
entity prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
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It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non‐compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in‐service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in‐service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1‐1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto‐generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built‐in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I‐17 (Transmission Relay System
Performance Comparison). Review of the I‐17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
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To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively‐known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self‐testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1‐1 through 1‐5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10‐year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self‐monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
Relay Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
Abnormal Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self‐monitoring capability is ST (for self test).
ST = 0 if there is no self‐monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time‐interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “time‐
interval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time‐interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six‐year interval for the
electromechanical relay, instead of the five‐year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10‐year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
40
facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance‐Based Maintenance process may be used to
establish maintenance intervals (PRC‐005 Attachment A Criteria for a Performance‐Based
Protection System Maintenance Program). A Performance‐Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance‐Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance‐Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance‐Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance‐Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001‐2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance‐Based Maintenance (PBM) program, the asset owner must
first sort the various Protection System Ccomponents into population segments. Any
population segment must be comprised of at least 60 individual units; if any asset owner opts
for PBM, but does not own 60 units to comprise a population, then that asset owner may
combine data from other asset owners until the needed 60 units is aggregated. Each
population segment must be composed of a grouping of Protection Systems or Ccomponents of
a consistent design standard or particular model or type from a single manufacturer and
subjected to similar environmental factors. For example: One segment cannot be comprised of
both GE & Westinghouse electro‐mechanical lock‐out relays; likewise, one segment cannot be
comprised of 60 GE lock‐out relays, 30 of which are in a dirty environment, and the remaining
30 from a clean environment. This PBM process cannot be applied to batteries, but can be
applied to all other cComponents of a Protection System, including (but not limited to) specific
battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics ‐ Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis ‐ Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
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2
z
n 1
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance‐Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance‐Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1‐1 through 1‐5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4%Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
to the requirements of the Standard. The requirements established for Performance‐Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power‐plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance‐Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance‐Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance‐Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in‐service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re‐calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
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errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human‐error is not pertinent data might be in the area of testing “86” lock‐out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial six‐
year interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human‐error caused tripping
incidents. In this example the human‐error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal‐performing segments in a Performance‐Based Maintenance system. Some examples are
listed below.
The maximum allowable interval, as established by the Performance‐Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
Identifiable sub‐groups of components within the established segment, which have
been identified to be the mal‐performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance‐Based Maintenance program in
order to remain within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal‐performance.
components within the mal‐performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal‐performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
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If you perform maintenance on a Protection System component for any reason (including as
part of a PRC‐004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance‐Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance‐Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock‐reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1‐1‐11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6‐1‐12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock‐reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
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All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance‐Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance‐changing criteria.
Similarly, Functional Entities that want to establish a condition‐based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands‐on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1‐4).
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE‐HEA lock‐out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
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48
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six‐year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
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Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or Ccomponents of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V‐insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper‐sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
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50
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real‐time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12‐
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
51
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested / year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
52
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off‐line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real‐time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment – Protection Systems or Ccomponents of a consistent design standard, or a particular
model or type from a single manufacturer that typically share other common elements.
Consistent performance is expected across the entire population of a segment. A segment must
contain at least sixty (60) individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built‐in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity‐accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
53
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note ‐ a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
54
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
55
10. Overlapping the Verification of Sections of the
Protection System
Tables 1‐1 through 1‐5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
Time‐based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1‐1 through 1‐5;
Monitoring as described in Tables 1‐1 through 1‐5;
A Performance‐Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto‐polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time‐interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance‐related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC‐018‐1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC‐002‐1 and PRC‐018‐1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single self‐
monitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non‐microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
59
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenance‐
activity‐time‐interval‐clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up‐rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC‐005‐2 3 are simple – if the
Protection System component performs a Protection System function, then it must be
maintained. If the component no longer performs Protection System functions, then it does
not require maintenance activities under the Tables of PRC‐005‐23. While many entities might
physically remove a component that is no longer needed, there is no requirement in PRC‐005‐2
3 to remove such component(s). Obviously, prudence would dictate that an “out‐of‐service”
device is truly made inactive. There are no record requirements listed in PRC‐005‐2 3 for
Protection System components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC‐005‐2 3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC‐005‐2 3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
60
The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
61
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self‐monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self‐monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands‐on
maintenance requirement), the manufacturers of the microprocessor‐based self‐monitoring
components in the Protection System should publish for the user a document or map that
shows:
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology‐neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
63
14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early‐generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC‐005‐2 3 requires specific
maintenance activities be accomplished within a specific time interval. As noted previously,
higher technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non‐electrical inputs are excluded.
Non‐microprocessor based equipment is treated differently than microprocessor‐based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
Non‐microprocessor devices must be tested with voltage and/or current applied to the
device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber‐optic Hall‐effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
65
protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real‐time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
Another method for proving the voltage and/or current‐sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current‐sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all‐inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi‐meters, voltmeter, clamp‐on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re‐check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi‐pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt‐meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual‐intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This six‐
year tripping requirement can be completed as easily as tracking the Real‐time Fault‐clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit‐interrupting device should not be confused with a motor‐operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high‐speed auto‐closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred‐tripping
device without the use of communications equipment. If this high‐speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring‐operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock‐out relay
(86) that may exist in any particular trip scheme. If the lock‐out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six‐year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non‐BES interrupting devices are not required. Normally‐open contacts
that are not used to pass a trip signal and normally‐closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC‐005‐2, other alarming relay control circuits,
(i.e., SF‐6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard‐wired trip circuitry with other methods of trip‐signal conveyance
such as fiber‐optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber‐optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC‐005‐2 3 testing requirements because the SDT is
unaware of industry‐recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐
17, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC‐005‐2 3 are intended to verify the integrity of tripping circuits, including
the breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing
the trip coil if a protection function operates. Beyond this, PRC‐005‐2 3 sets no requirements
for verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1‐5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC‐005‐2 3 includes high‐speed grounding switch trip coils within the dc control circuitry
to the degree that the initiating Protection Systems are characterized as “transmission
Protection Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non‐BES circuit breaker that is tripped via a Protection
System to which PRC‐005‐2 3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non‐black‐start) radial Loads but has a trip that originates from an under‐frequency
(81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non‐BES breaker that is tripped via a Protection
System to which PRC‐005‐2 3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non‐black‐start) radial Loads but has a trip that originates from a BES 115KV
line relay.
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock‐out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock‐out (86) (or auxiliary (94)) relay and the
non‐BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non‐BES circuit breaker that is tripped via a
Protection System to which PRC‐005‐2 3 applies, such as the generator field breaker and low‐
side breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliairyauxiliary tripping relays are not required since these breakers
may be associated with radially fed loads and are not considered to be BES breakers. An
example of an otherwise non‐BES circuit breaker that is tripped via a BES protection component
might be (but is not limited to) a 6.9kV station service transformer source circuit breaker but
has a trip that originates from a generator differential (87) relay.
The differential relay must be verified.
The current signals to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
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Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
Operation of normally‐closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
Protective relays which respond to electrical quantities,
Communications Systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1‐4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance‐Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance‐changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC‐005‐2 3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
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technologies that provide a source of dc supply that does not include either a battery or
charger.
Battery Charger ‐ The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery ‐ Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1‐4.
Emerging Technologies ‐ Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1‐4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1‐4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor‐based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
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harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one‐ to two‐
second delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp‐range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior of
the various dc‐supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor‐controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
Internal ohmic measurements of the cells and units of lead‐acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
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No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1‐4 to insure that the
station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve‐regulated lead‐acid, vented
lead‐acid, or nickel‐cadmium) and the maintenance activity chosen.
For example, if you have a valve‐regulated lead‐acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the six‐
month interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead‐acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six‐months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve‐regulated lead‐acid (VRLA) batteries and vented lead‐acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer‐supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead‐acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel‐cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve‐regulated lead‐acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1‐4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell‐to‐cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1‐4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1‐4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell‐to‐cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1‐4 by a Performance‐Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1‐4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1‐4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot‐checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally‐accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel‐cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel‐cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel‐cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel‐cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel‐cadmium batteries,
there are no significantly measurable properties of the nickel‐cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1‐4(c)
(Protection System Station dc supply Using nickel‐cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-2 3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check‐off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check‐off per battery bank is sufficient for documentation, as long as the single check‐
off attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC‐005‐2 3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve‐Regulated Lead‐Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead‐Acid (VLA)
batteries were unable to be used on this new type of lead‐acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188‐2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1‐4. In cases where individual cells in a multi‐cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1‐4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead‐acid (VLA) and nickel‐cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1‐4. Because
the electrolyte level in valve‐regulated lead‐acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1‐4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved‐quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve‐regulated lead‐acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1‐4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead‐acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry‐out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1‐4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six‐month test” at Row 4 on Table 1‐4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1‐4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six‐month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline ‐ others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six‐month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1‐4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self‐
monitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1‐4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1‐4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1‐4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1‐4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1‐4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1‐4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1‐4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications‐assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications‐assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communications‐
assisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber‐optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on‐site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
On‐off power‐line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check‐back test from one terminal.
Systems which use frequency‐shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss‐of‐guard indication or alarm. For frequency‐shift power‐line carrier systems, the
guard signal level meter can also be checked.
Hard‐wired pilot wire line Protection Systems typically have pilot‐wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
On‐off power‐line carrier systems can be shown to be operational by automated
periodic power‐line carrier check‐back tests with remote alarming of failures.
Systems which use a frequency‐shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss‐of‐guard alarm or low signal level alarm.
Hard‐wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot‐wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements, including signal‐to‐noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four‐month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
Power Line Carrier (PLC) ‐ The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical‐electrical signal format converters are the associated
communications equipment
Figure 1‐2, A‐1 and A‐2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
An on‐off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check‐back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre‐determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1‐1 through 1‐5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto‐polling system; the only
requirement is that the alarm be brought to the action‐site within 24 hours. This effectively
makes manned‐stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned‐station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non‐manned‐
station, which is that if the monitored point has an alarm that is auto‐reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail‐safe “form‐b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1‐1. Voltage and current‐sensing devices have the same maintenance activity and
interval as Table 1‐3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
Verify the trip path between the relay and lock‐out and/or auxiliary tripping device(s).
Verify operation of any lock‐out and/or auxiliary tripping device(s) used in the trip
circuit.
No verification of trip path required between the lock‐out (and/or auxiliary tripping
device) and the non‐BES interrupting device.
No verification of trip path required between the relay and trip coil for circuits that have
no lock‐out and/or auxiliary tripping device(s).
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non‐BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load‐Shed relay and lock‐out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock‐out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under‐frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non‐BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock‐out relay. While many failures of these distributed system circuit breakers (or
non‐BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non‐BES device, such as a battery bank that serves both a BES circuit breaker and a non‐BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during under‐
frequency or under‐voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load‐generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC‐005‐3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC‐005‐3.
15.8.1 Frequently-asked Questions
None
15..8 9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team
recognizes that there are concurrent evidence requirements of other NERC standards that
could, at times, fulfill evidence requirements of this Standard.
15..89.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check‐off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
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If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-00523?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC‐016 could work for the activity tracking requirements
under this PRC‐005‐23.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
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References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor‐Based
Transmission‐Line Protective Relays, Part I ‐ Explanation of the Statistics, and Part II ‐
Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016‐6
PWRD and 96WM 127‐1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR‐ 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve‐
Regulated Lead‐Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead‐Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45‐2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented Lead‐
Acid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR‐100248, 1006757, August 2002.
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
95
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” ‐ Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
PRC‐005‐2 3 Supplementary Reference and FAQ – October 2012April 2013
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC‐005‐2, and also
may not be all‐inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
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Figure 1 & 2 Legend – components Components of Protection Systems
Number in
Figure
component
Component of
Protection System
Includes
Excludes
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
Devices that use non‐electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync‐check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber‐optic systems that
carry a trip signal as well as hard‐
wired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
Tele‐protection equipment used
Communications
to convey specific information, in
systems necessary
the form of analog or digital
for correct operation
signals, necessary for the correct
of protective
operation of protective functions.
functions
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
4
5
Additional information can be found in References
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Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A‐1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two‐terminal pilot protection scheme to protect for line Faults, and to avoid over‐
tripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self‐monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self‐monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
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5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on‐off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check‐back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A‐2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
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contacts of a small telephone‐type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check‐back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone‐type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally‐occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC‐005‐3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front‐panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay‐carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle Ashton
Tri‐State G&T
Bob Bentert
Florida Power & Light Company
Forrest Brock
Western Farmers Electric Cooperative
Aaron Feathers
Pacific Gas and Electric Company
Sam Francis
Oncor Electric Delivery
Carol Gerou
Midwest Reliability Organization
Russell C. Hardison
Tennessee Valley Authority
David Harper
NRG Texas Maintenance Services
James M. Kinney
FirstEnergy Corporation
Mark Lucas
ComEd
Kristina Marriott
ENOSERV
Al McMeekin
NERC
Michael Palusso
Southern California Edison
Mark Peterson
Great River Energy
John Schecter
American Electric Power
William D. Shultz
Southern Company Generation
Eric A. Udren
Quanta Technology
Scott Vaughan
City of Roseville Electric Department
Matthew Westrich
American Transmission Company
Philip B. Winston
Southern Company Transmission
David Youngblood
Luminant Power
John A. Zipp
ITC Holdings
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Table of Issues and Directives
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Table of Issues and Directives Associated with PRC‐005‐3
Source
FERC Order
758
Directive Language
(including pg #)
Disposition
27. We note that the original project to revise
Specific minimum activities and maximum
Reliability Standard PRC‐005 failed a recirculation allowable intervals are included in the draft
ballot in July of 2011. The project was
standard within Table 4.
subsequently reinitiated to continue the efforts
to develop Reliability Standard PRC‐005‐2. Given
that the project to draft proposed revisions to
Reliability Standard PRC‐005‐1 continues in this
reinitiated effort, and the importance of
maintaining and testing reclosing relays, we
direct NERC to include maintenance and testing
of reclosing relays that can affect the reliable
operation of the Bulk‐Power System, as discussed
above, within these reinitiated efforts to revise
Reliability Standard PRC‐005.
Section and/or
Requirement(s)
Applicability 4.2.6
Requirement R1, R3,
Requirement R4, Table 4
138 FERC ¶ 61,094
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 40
[Docket No. RM10-5-000; Order No. 758]
Interpretation of Protection System Reliability Standard
(Issued February 3, 2012)
AGENCY: Federal Energy Regulatory Commission
ACTION: Final Rule
SUMMARY: On November 17, 2009, the North American Electric Reliability
Corporation (NERC) submitted a petition (Petition) requesting approval of NERC’s
interpretation of Requirement R1 of Commission-approved Reliability Standard PRC005-1 (Transmission and Generation Protection System Maintenance and Testing). On
December 16, 2010, the Commission issued a Notice of Proposed Rulemaking (NOPR).
in the NOPR, the Commission proposed to accept the NERC proposed interpretation of
Requirement R1 of Reliability Standard PRC-005-1, and proposed to direct NERC to
develop modifications to the PRC-005-1 Reliability Standard through its Reliability
Standards development process to address gaps in the Protection System maintenance
and testing standard that were highlighted by the proposed interpretation. As a result of
the comments received in response to the NOPR, in this order the Commission adopts the
NOPR proposal to accept NERC’s proposed interpretation. In addition, as discussed
below, the Commission accepts, in part, NERC’s commitment to address the concerns in
the Protection System maintenance and testing standard that were identified by the NOPR
Docket No. RM10-5-000
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within the Reliability Standards development process, and directs, in part, that the
concerns identified by the NOPR with regard to reclosing relays be addressed within the
reinitiated PRC-005 revisions.
EFFECTIVE DATE: This rule will become effective 30 days after publication in the
FEDERAL REGISTER.
FOR FURTHER INFORMATION CONTACT:
Ron LeComte (Legal Information)
Office of General Counsel
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(202) 502-8405
[email protected]
Danny Johnson (Technical Information)
Office of Electric Reliability
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(202) 502-8892
[email protected]
SUPPLEMENTARY INFORMATION:
138 FERC ¶ 61,094
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: Jon Wellinghoff, Chairman;
Philip D. Moeller, John R. Norris,
and Cheryl A. LaFleur.
Interpretation of Protection System Reliability Standard
Docket No. RM10-5-000
ORDER NO. 758
FINAL RULE
(Issued February 3, 2012)
1.
On November 17, 2009, NERC submitted the Petition requesting approval of
NERC’s interpretation of Requirement R1 of Commission-approved Reliability Standard
PRC-005-1 (Transmission and Generation Protection System Maintenance and Testing).
NERC developed the interpretation in response to a request for interpretation submitted
to NERC by the Regional Entities Compliance Monitoring Processes Working Group
(Working Group).1 In a December 16, 2010 Notice of Proposed Rulemaking (NOPR), 2
the Commission proposed to accept the NERC proposed interpretation of Requirement
R1 of Reliability Standard PRC-005-1, and proposed to direct NERC to develop
modifications to the PRC-005-1 Reliability Standard through its Reliability Standards
1
The Working Group is a subcommittee of the Regional Entity Management
Group which consists of the executive management of the eight Regional Entities.
2
Interpretation of Protection System Reliability Standard, Notice of Proposed
Rule Making, 75 FR 81,152 (Dec. 27, 2010), FERC Stats. & Regs. ¶ 32,669 (2010).
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development process to address gaps in the Protection System maintenance and testing
standard highlighted by the proposed interpretation. As a result of the comments
received in response to the NOPR, in this order the Commission adopts the NOPR
proposal to accept NERC’s proposed interpretation. In addition, the Commission
accepts, in part, NERC’s commitments to address the concerns in the Protection System
maintenance and testing standard that were identified by the NOPR within the Reliability
Standards development process, and directs, in part, that the concerns identified by the
NOPR with regard to reclosing relays be addressed within the reinitiated PRC-005
revisions.
I.
Background
2.
Section 215 of the Federal Power Act (FPA) requires a Commission-certified
Electric Reliability Organization (ERO) to develop mandatory and enforceable
Reliability Standards, which are subject to Commission review and approval. 3
Specifically, the Commission may approve, by rule or order, a proposed Reliability
Standard or modification to a Reliability Standard if it determines that the Standard is
just, reasonable, not unduly discriminatory or preferential, and in the public interest. 4
3
16 U.S.C. 824 (2006).
4
Id. 824o(d)(2).
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Once approved, the Reliability Standards may be enforced by the ERO, subject to
Commission oversight, or by the Commission independently.5
3.
Pursuant to section 215 of the FPA, the Commission established a process to select
and certify an ERO,6 and subsequently certified NERC.7 On April 4, 2006, NERC
submitted to the Commission a petition seeking approval of 107 proposed Reliability
Standards. On March 16, 2007, the Commission issued a Final Rule, Order No. 693, 8
approving 83 of the 107 Reliability Standards, including Reliability Standard PRC-005-1.
In addition, pursuant to section 215(d)(5) of the FPA, 9 the Commission directed NERC to
develop modifications to 56 of the 83 approved Reliability Standards, including PRC005-0. 10
5
Id. 824o(e)(3).
6
Rules Concerning Certification of the Electric Reliability Organization; and
Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order on reh’g, Order
No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
7
North American Electric Reliability Corp., 116 FERC ¶ 61,062, order on reh’g
& compliance, 117 FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. FERC, 564 F.3d
1342 (D.C. Cir. 2009).
8
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693,
FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007).
9
16 U.S.C. 824o(d)(5).
10
Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1475.
Docket No. RM10-5-000
4.
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NERC’s Rules of Procedure provide that a person that is “directly and materially
affected” by Bulk-Power System reliability may request an interpretation of a Reliability
Standard. 11 In response, the ERO will assemble a team with relevant expertise to address
the requested interpretation and also form a ballot pool. NERC’s Rules of Procedure
provide that, within 45 days, the team will draft an interpretation of the Reliability
Standard and submit it to the ballot pool. If approved by the ballot pool and subsequently
by the NERC Board of Trustees (Board), the interpretation is appended to the Reliability
Standard and filed with the applicable regulatory authorities for approval.
II.
Reliability Standard PRC-005-1
5.
The purpose of PRC-005-1 is to “ensure all transmission and generation Protection
Systems affecting the reliability of the Bulk Electric System (BES) are maintained and
tested.” In particular, Requirement R1, requires that:
R1. Each Transmission Owner and any Distribution Provider that owns a transmission
Protection System and each Generator Owner that owns a generation Protection System
shall have a Protection System maintenance and testing program for Protection Systems
that affect the reliability of the BES. The program shall include:
R1.1. Maintenance and testing intervals and their basis.
11
NERC Rules of Procedure, Appendix 3A, Reliability Standards Development
Procedure, Version 6.1, at 26-27 (2007).
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R1.2. Summary of maintenance and testing procedures.
6.
NERC currently defines “Protection System” as follows: “Protective relays,
associated communication systems, voltage and current sensing devices, station batteries
and DC control circuitry.” 12
III.
NERC Proposed Interpretation
7.
In the NERC Petition, NERC explains that it received a request from the Working
Group for an interpretation of Reliability Standard PRC-005-1, Requirement R1,
addressing five specific questions. Specifically, the Working Group questions and NERC
proposed interpretations include:
Request 1: “Does R1 require a maintenance and testing program for the battery chargers
for the ‘station batteries’ that are considered part of the Protection System?”
Response: “While battery chargers are vital for ensuring ‘station batteries’ are available
to support Protection System functions, they are not identified within the definition of
12
In Docket No. RD11-13-000, NERC has proposed to revise the definition of
Protection System effective on the first day of the first calendar quarter twelve months
from approval. The Commission is approving this revision in an order issued
concurrently with this order. See North American Electric Reliability Corp., 138 FERC
¶ 61,095 (2012).
Docket No. RM10-5-000
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‘Protection Systems.’ Therefore, PRC-005-1 does not currently require maintenance and
testing of battery chargers.” 13
Request 2: “Does R1 require a maintenance and testing program for auxiliary relays and
sensing devices? If so, what types of auxiliary relays and sensing devices? (i.e.,
transformer sudden pressure relays).”
Response: “The existing definition of ‘Protection System’ does not include
auxiliary relays; therefore, maintenance and testing of such devices is not
explicitly required. Maintenance and testing of such devices is addressed to the
degree that an entity’s maintenance and testing program for DC control circuits
involves maintenance and testing of imbedded auxiliary relays. Maintenance and
testing of devices that respond to quantities other than electrical quantities (for
example, sudden pressure relays) are not included within Requirement R1.”
Request 3: “Does R1 require maintenance and testing of transmission line re-closing
relays?”
Response: “No. ‘Protective Relays’ refer to devices that detect and take action for
13
The revised definition of Protection System accepted in Docket No. RD11-13000 includes battery chargers as an element of the Protection System and, as a result of
that change, battery chargers must be maintained and tested. Thus, the modified
definition of Protection System approved in Docket No. RD11-13-000, when effective,
shall supersede the interpretation of Requirement R1 of Reliability Standard PRC-005-1
approved in this order.
Docket No. RM10-5-000
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abnormal conditions. Automatic restoration of transmission lines is not a ‘protective’
function.”
Request 4: “Does R1 require a maintenance and testing program for the DC circuitry
that is just the circuitry with relays and devices that control actions on breakers, etc., or
does R1 require a program for the entire circuit from the battery charger to the relays to
circuit breakers and all associated wiring?”
Response: “PRC-005-1 requires that entities 1) address DC control circuitry within their
program, 2) have a basis for the way they address this item, and 3) execute the program.
Specific additional requirements relative to the scope and/or methods are not
established.”
Request 5: “For R1, what are examples of ‘associated communications systems’ that are
part of ‘Protection Systems’ that require a maintenance and testing program?”
Response: “Associated communication systems” refer to communication systems used
to convey essential Protection System tripping logic, sometimes referred to as pilot
relaying or teleprotection. Examples include the following:
- communications equipment involved in power-line-carrier relaying;
- communications equipment involved in various types of permissive protection system
applications;
- direct transfer-trip systems;
- digital communication systems ... .”
Docket No. RM10-5-000
8.
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In its Petition requesting that the Commission accept the proposed interpretation,
NERC recognized that greater clarity to the requirement language in PRC-005-1a is
necessary to provide a complete framework for maintenance and testing of equipment
necessary to ensure the reliability of the Bulk Power System. In its Petition, NERC also
stated that this activity is already underway in the scope of Project 2007-17 – Protection
System Maintenance and Testing, coupled with the revised definition of Protection
System.
IV.
Commission NOPR
9.
In the NOPR, the Commission proposed to accept the NERC proposed
interpretation of Requirement R1 of Reliability Standard PRC-005-1. In addition, the
Commission proposed to direct NERC to develop modifications to the PRC-005-1
Reliability Standard through its Reliability Standards development process to address
gaps in the Protection System maintenance and testing standard that were highlighted by
the proposed interpretation. The specific modifications are discussed below.
V.
Comments
10.
Comments on the Commission’s proposed interpretation were received by the
NERC, Edison Electric Institute (EEI), ISO/RTO Council (IRC), American Public Power
Association (APPA), National Rural Electric Cooperative Association (NRECA),
Transmission Access Policy Study Group (TAPS), Cities of Anaheim and Riverside,
Docket No. RM10-5-000
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California (Joint Cities), Northwest Commenters, 14 International Transmission Company
(ITC), PSEG Companies, 15 and MidAmerican Energy Holdings Company
(MidAmerican), Constellation/CENG, 16 and Manitoba Hydro (Manitoba). In general,
commenters support NERC’s proposed interpretation, and oppose the further directives in
the NOPR. Commenters also state that modifications to the Reliability Standards should
be addressed within the NERC standards development process and that certain of the
modifications are currently being addressed.
VI.
Discussion
11.
As a result of the comments received in response to the proposal, the Commission
adopts the NOPR proposal to accept NERC’s proposed interpretation. As discussed
below, 17 the Commission accepts, in part, NERC’s commitments to address the concerns
14
Lincoln People’s Utility District, Columbia River People’s Utility District,
Inland Power and Light Company, Northwest Public Power Association, Northwest
Requirements Utilities, Pacific Northwest Generating Cooperative, Public Power
Council, Public Utility District No. 1 of Snohomish County, and Tillamook People’s
Utility District.
15
Public Service Electric and Gas Company, PSEG Fossil LLC, and PSEG
Nuclear LLC.
16
Constellation Energy Group, Inc., Baltimore Gas & Electric Company,
Constellation Energy Commodities Group, Inc., Constellation Energy Control and
Dispatch, LLC, Constellation NewEnergy, Inc., and Constellation Power Source
Generation, Inc. (together, Constellation) and Constellation Energy Nuclear Group, LLC
(CENG).
17
See infra, P 15, P 18, P 20.
Docket No. RM10-5-000
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in the Protection System maintenance and testing standard that were identified by the
NOPR within the Reliability Standards development process, and directs, in part, that the
concerns identified by the NOPR with regard to reclosing relays be addressed within the
reinitiated PRC-005 revisions.
A.
12.
Maintenance and Testing of Auxiliary and Non-Electrical Sensing
Relays
In the NOPR, the Commission noted a concern that the proposed interpretation
may not include all components that serve in some protective capacity. 18 The
Commission’s concerns included the proposed interpretation’s exclusion of auxiliary and
non-electrical sensing relays. The Commission proposed to direct NERC to develop a
modification to the Reliability Standard to include any component or device that is
designed to detect defective lines or apparatuses or other power system conditions of an
abnormal or dangerous nature, including devices designed to sense or take action against
any abnormal system condition that will affect reliable operation, and to initiate
appropriate control circuit actions.
13.
In their comments NERC, EEI, Joint Cities, Manitoba, NRECA, ITC,
MidAmerican, and PSEG expressed varying levels of disagreement with the NOPR’s
proposed directive. The disagreements are based on a concern that the proposed directive
18
NOPR at P 11-14.
Docket No. RM10-5-000
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will create an increase in scope that will capture many items not used in BES protection.
NERC is concerned the scope of this proposed directive is so broad that any device that is
installed on the Bulk-Power System to monitor conditions in any fashion may be
included. 19 NERC states that many of these devices are advisory in nature and should
not be reflected within NERC Reliability Standards if they do not serve a necessary
reliability purpose. 20 NERC does not believe it is necessary for the Commission to issue
a directive to address this issue. Instead, NERC proposes to develop, either
independently or in association with other technical organizations such as IEEE, one or
more technical documents which:
1. describe the devices and functions (to include sudden pressure relays which trip
for fault conditions) that should address FERC’s concern; and
2. propose minimum maintenance activities for such devices and maximum
maintenance intervals, including the technical basis for each. 21
14.
NERC states that these technical documents will address those protective relays
that are necessary for the reliable operation of the Bulk-Power System and will allow for
differentiation between protective relays that detect faults from other devices that monitor
19
NERC February 25, 2011 Comments at 7.
20
Id.
21
Id.
Docket No. RM10-5-000
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the health of the individual equipment and are advisory in nature (e.g., oil temperature).
Following development of the above-referenced document(s), NERC states that it will
“propose a new or revised standard (e.g. PRC-005) using the NERC Reliability Standards
development process to include maintenance of such devices, including establishment of
minimum maintenance activities and maximum maintenance intervals.” 22 Accordingly,
NERC proposes to “add this issue to the Reliability Standards issues database for
inclusion in the list of issues to address the next time the PRC-005 standard is revised.” 23
15.
The Commission accepts NERC’s proposal, and directs NERC to file, within sixty
days of publication of this Final Rule, a schedule for informational purposes regarding
the development of the technical documents referenced above, including the
identification of devices that are designed to sense or take action against any abnormal
system condition that will affect reliable operation. NERC shall include in the
informational filing a schedule for the development of the changes to the standard that
NERC stated it would propose as a result of the above-referenced documents. 24 NERC
should update its schedule when it files its annual work plan.
22
23
24
Id.
Id.
Id. at 7, 8.
Docket No. RM10-5-000
B.
16.
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Reclosing Relays
In the NOPR, the Commission noted that while a reclosing relay is not identified
as a specific component of the Protection System, if it either is used in coordination with
a Protection System to achieve or meet system performance requirements established in
other Commission–approved Reliability Standards, or can exacerbate fault conditions
when not properly maintained and coordinated, then excluding the maintenance and
testing of these reclosing relays will result in a gap in the maintenance and testing of
relays affecting the reliability of the Bulk-Power System. 25 Accordingly, the
Commission proposed that NERC modify the Reliability Standard to include the
maintenance and testing of reclosing relays affecting the reliability of the Bulk-Power
System.
17.
NERC, EEI, IRC, ITC MidAmerican, NRECA, and PSEG opposed the NOPR’s
directive to include reclosing relays. In general, commenters state that reclosing relays
used for stability purposes are already included in maintenance and testing programs, and
that reclosing relays that are primarily used to minimize customer outages times and
maximize availability of system components should not be included. PSEG and
MidAmerican contend that the NERC standards development process should be utilized
25
NOPR at P 15.
Docket No. RM10-5-000
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to determine the maintenance and testing of those reclosing relays that affect the
reliability of the Bulk-Power System.
18.
ISO/RTO contends that the primary purpose of reclosing relays is to allow more
expeditious restoration of lost components of the system, not to maintain the reliability of
the Bulk-Power System. Therefore, ISO/RTO maintains that automatic reclosing relays
should not be subject to the NERC Reliability Standard for relay maintenance and testing.
MidAmerican states that there are only limited circumstances when a reclosing relay can
actually affect the reliability of the Bulk-Power System. MidAmerican contends that it
would be overbroad for the Commission to direct a modification to the standard that
encompasses all reclosing relays that can “exacerbate fault conditions when not properly
maintained and coordinated,” as this would improperly include many types of reclosing
relays that do not necessarily affect the reliability of the Bulk-Power System.
19.
ITC agrees with the Commission’s proposal that reclosing relays that are required
for system stability should be maintained and tested under Requirement R1 of PRC-0051. However, ITC contends that since most bulk electric system automatic reclosing relay
systems are applied to minimize customer outage times and to maximize availability of
system components, only some “high speed” reclosing relays will affect the reliability of
the Bulk-Power System. Therefore, ITC proposes that the Commission should direct
NERC to draft specific requirements or selection criteria that should be used in
Docket No. RM10-5-000
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identifying the types of re-closing relays for maintenance and testing under Requirement
R1 of PRC-005-1. 26
20.
While NRECA notes that reclosing relays operate to restore, not protect a system,
NRECA also notes that there are reclosing schemes that directly affect and are required
for automatic stability control of the system, but that such schemes are already covered
under Special Protection Schemes that are subject to reliability standards. NRECA, notes
that some transmission operators do not allow reclosing relays on the bulk power system
to remove the possibility of reclosing in on a permanent fault, thus avoiding further
potential damage to the bulk power system. 27
21.
Similarly, NERC comments that in most cases reclosing relays cannot be relied on
to meet system performance requirements because of the need to consider the impact of
auto-reclosing into a permanent fault; however, NERC states that applications that may
exist in which automatic restoration is used to meet system performance requirements
following temporary faults. NERC comments that where reclosing relays are applied to
meet performance requirements in approved NERC Reliability Standards, or where
automatic restoration of service is fundamental to derivation of an Interconnection
Reliability Operating Limit (IROL), it is reasonable to require maintenance and testing of
26
ITC Comments at 7.
27
NRECA Comments at 13-14.
Docket No. RM10-5-000
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auto-reclosing relays. 28 However, NERC does not believe it is necessary for the
Commission to issue a directive. 29 NERC states that the proposed revisions to Reliability
Standard PRC-005-1 that are under development include maintenance of reclosing
devices that are part of Special Protection Systems. 30 NERC proposes “to add the
remaining concerns relating to this issue to the Reliability Standards issues database for
inclusion in the list of issues to address the next time Reliability Standard PRC-005 is
revised.” 31
22.
As NERC and other commenters point out, reclosing relays are used in a broad
range of applications; e.g., meet system performance requirements in approved
Reliability Standards, derivation of IROLs, maintain system stability, minimize customer
outage times, to maximize availability of system components, etc. While commenters
acknowledge that reclosing relays have several applications, commenters also appear to
be divided on which applications, if any, should be included in a maintenance and testing
program.
28
NERC February 25, 2011 Comments at 9.
29
TAPs urges the Commission to use its authority pursuant to section 215(d)(5) in
circumstances where there is a clear need for such a directive.
30
Id.
31
Id.
Docket No. RM10-5-000
23.
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The NOPR raised a concern that excluding the maintenance and testing of
reclosing relays that can exacerbate fault conditions when not properly maintained and
coordinated will result in a gap affecting Bulk-Power System reliability. 32 We agree with
MidAmerican that while there are only limited circumstances when a reclosing relay can
actually affect the reliability of the Bulk-Power System, there are some reclosing relays,
e.g., whose failure to operate or that misoperate during an event due to lack of
maintenance and testing, may negatively impact the reliability of the Bulk-Power
System. 33 We agree with NERC that where reclosing relays are applied to meet
performance requirements in approved NERC Reliability Standards, or where automatic
restoration of service is fundamental to derivation of an Interconnection Reliability
Operating Limit (IROL), it is reasonable to require maintenance and testing of autoreclosing relays.
24.
In the NOPR we stated that a misoperating or miscoordinated reclosing relay may
result in the reclosure of a Bulk-Power System element back onto a fault or that a
misoperating or miscoordinated reclosing relay may fail to operate after a fault has been
cleared, thus failing to restore the element to service. As a result, the reliability of the
32
NOPR at P 15, noting one such outage resulting in the loss of over 4,000 MW of
generation and multiple 765 kV lines.
33
MidAmerican Comments at 6.
Docket No. RM10-5-000
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Bulk-Power System would be affected. In addition, misoperated or miscoordinated
relays may result in damage to the Bulk-Power System. For example, a misoperation or
miscoordination of a reclosing relay causing the reclosing of Bulk-Power System
facilities into a permanent fault can subject generators to excessive shaft torques and
winding stresses and expose circuit breakers to systems conditions less than optimal for
correct operation, potentially damaging the circuit breaker. 34
25.
While some commenters argue that reclosing relays do not affect the reliability of
the Bulk-Power System, the record supports our concern. For example, we note NERC’s
concern regarding the “… need to consider the impact of autoreclosing into a permanent
fault.” We also note NRECA’s comments that “… some transmission operators do not
allow reclosing on the bulk electric system facilities to remove the opportunity of closing
in on a permanent fault” and “… by its [automatic reclosing] use a utility understands the
potential for further damage that may occur by reclosing.” 35 Because the misoperation or
miscommunication of reclosing relays can exacerbate fault conditions, we find that
34
NERC System Protection and Control Subcommittee, "Advantages and
Disadvantages of EHV Automatic Reclosing, "December 9, 2009, p. 14.
35
NRECA Comments at 13.
Docket No. RM10-5-000
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reclosing relays that may affect the reliability of the Bulk-Power System should be
maintained and tested. 36
26.
For the reasons discussed above, we conclude that it is important to maintain and
test reclosing relays that may affect the reliability of the Bulk-Power System. We agree
with ITC that specific requirements or selection criteria should be used to identify
reclosing relays that affect the reliability of the Bulk-Power System. As MidAmerican
suggests, the standard should be modified, through the Reliability Standards development
process, to provide the Transmission Owner, Generator Owner, and Distribution Provider
with the discretion to include in a Protection System maintenance and testing program
only those reclosing relays that the entity identifies as having an affect on the reliability
of the Bulk-Power System.
27.
We note that the original project to revise Reliability Standard PRC-005 failed a
recirculation ballot in July of 2011. The project was subsequently reinitiated to continue
the efforts to develop Reliability Standard PRC-005-2. Given that the project to draft
proposed revisions to Reliability Standard PRC-005-1 continues in this reinitiated effort,
and the importance of maintaining and testing reclosing relays, we direct NERC to
include maintenance and testing of reclosing relays that can affect the reliable operation
36
As NERC notes, there may be applications of reclosing relays where the
misoperation or miscommunication may does not have a detrimental effect on the
reliability of the Bulk-Power System.
Docket No. RM10-5-000
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of the Bulk-Power System, as discussed above, within these reinitiated efforts to revise
Reliability Standard PRC-005. 37
C.
28.
DC Control Circuitry and Components
In the NOPR, the Commission explained its understanding that a maintenance and
testing program for DC control circuitry would include all components of DC control
circuitry necessary for ensuring Reliable Operation of the Bulk-Power System, and that
not establishing the specific requirements of such a maintenance and testing program
results in a gap in the maintenance and testing of Protection System components. 38
29.
Joint Cities, MidAmerican, and NRECA expressed concern that the NOPR’s
directive is too broad and unnecessarily burdensome. NERC agrees that maintenance and
testing should be required for all DC control circuitry. 39 NERC further stated that draft
standard PRC-005-2 being developed in Project 2007-17 “includes extensive, specific
maintenance activities (with maximum maintenance intervals) related to the DC control
37
On December 13, 2011, NERC submitted its Standards Development Plan for
2012-2014. NERC estimates that Project 2007-17 will be completed in the second
quarter of 2012. By July 30, 2012, NERC should submit to the Commission either the
completed project which addresses the remaining issues consistent with this order, or an
informational filing that provides a schedule for how NERC will address such issues in
the Project 2007-17 reinitiated efforts.
38
NOPR at P 16.
39
NERC February 25, 2011 Comments at 10.
Docket No. RM10-5-000
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circuits.” 40 The Commission accepts NERC’s commitment to include the development
of specific requirements of such a maintenance and testing program described above in
Project 2007-17. 41
VII.
Information Collection Statement
30.
The Office of Management and Budget (OMB) regulations require that OMB
approve certain reporting and recordkeeping (collections of information) imposed by an
agency. 42 The Commission submits reporting and recording keeping requirements to
OMB under section 3507 of the Paperwork Reduction Act of 1995. 43
31.
As stated above, the Commission previously approved, in Order No. 693, the
Reliability Standard that is the subject of the current Final Rule. This Final Rule accepts
an interpretation of the currently approved Reliability Standard. The interpretation of the
current Reliability Standard at issue in this final rule is not expected to change the
reporting burden or the information collection requirements. The informational filing
40
Id.
41
As previously noted, NERC estimates that Project 2007-17 will be completed by
the second quarter of 2012. By July 30, 2012, NERC should submit to the Commission
either the completed project which addresses the remaining issues consistent with this
order, or an informational filing that provides a schedule for how NERC will address
such issues in the Project 2007-17 reinitiated efforts.
42
5 CFR 1320.
43
44 U.S.C. 3507.
Docket No. RM10-5-000
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required of NERC is part of currently active collection FERC-725 and does not require
additional approval by OMB.
32.
We will submit this final rule to OMB for informational purposes only.
VIII. Environmental Analysis
33.
The Commission is required to prepare an Environmental Assessment or an
Environmental Impact Statement for any action that may have a significant adverse effect
on the human environment. 44 The Commission has categorically excluded certain
actions from this requirement as not having a significant effect on the human
environment. Included in the exclusion are rules that are clarifying, corrective, or
procedural or that do not substantially change the effect of the regulations being
amended. 45 The actions proposed herein fall within this categorical exclusion in the
Commission’s regulations.
IX.
Regulatory Flexibility Act
34.
The Regulatory Flexibility Act of 1980 (RFA) generally requires a description and
analysis of final rules that will have significant economic impact on a substantial number
of small entities. 46 The RFA mandates consideration of regulatory alternatives that
44
Regulations Implementing the National Environmental Policy Act of 1969,
Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).
45
18 CFR 380.4(a)(2)(ii).
46
5 U.S.C. 601-612.
Docket No. RM10-5-000
- 23 -
accomplish the stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small Business
Administration’s (SBA) Office of Size Standards develops the numerical definition of a
small business. 47 The SBA has established a size standard for electric utilities, stating
that a firm is small if, including its affiliates, it is primarily engaged in the transmission,
generation and/or distribution of electric energy for sale and its total electric output for
the preceding twelve months did not exceed four million megawatt hours. 48 The RFA is
not implicated by this Final Rule because the interpretation accepted herein does not
modify the existing burden or reporting requirements. Because this Final Rule accepts an
interpretation of the currently approved Reliability Standard, the Commission certifies
that this Final Rule will not have a significant economic impact on a substantial number
of small entities.
X.
Document Availability
35.
In addition to publishing the full text of this document in the Federal Register, the
Commission provides all interested persons an opportunity to view and/or print the
contents of this document via the Internet through FERC's Home Page
(http://www.ferc.gov) and in FERC's Public Reference Room during normal business
47
13 CFR 121.201.
48
Id. n.1.
Docket No. RM10-5-000
- 24 -
hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A,
Washington, DC 20426.
36.
From FERC's Home Page on the Internet, this information is available on
eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft
Word format for viewing, printing, and/or downloading. To access this document in
eLibrary, type the docket number excluding the last three digits of this document in the
docket number field.
37.
User assistance is available for eLibrary and the FERC’s website during normal
business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676)
or email at [email protected], or the Public Reference Room at (202) 5028371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
XI.
Effective Date and Congressional Notification
38.
This Final Rule is effective 30 days from publication in Federal Register. The
Commission has determined, with the concurrence of the Administrator of the Office of
Information and Regulatory Affairs of OMB that this rule is not a “major rule” as defined
in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996.
List of subjects in 18 CFR Part 40
Applicability
Mandatory Reliability Standards
Availability of Reliability Standards
Docket No. RM10-5-000
- 25 -
By the Commission.
(SEAL)
Nathaniel J. Davis, Sr.,
Deputy Secretary.
July 30, 2012
Ms. Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
RE:
Informational Filing in Compliance with Order No. 758 – Interpretation of
Protection System Reliability Standard, Docket No. RM10-5-000
Dear Ms. Bose,
On February 3, 2012, the Federal Energy Regulatory Commission (“Commission”)
issued Order No. 758, approving the North American Electric Reliability Corporation (“NERC”)
interpretation of Requirement R1 of Commission-approved Reliability Standard PRC-005-1 ―
Transmission and Generation Protection System Maintenance and Testing. 1
In Order No. 758, the Commission also accepted NERC’s commitments to address the
concerns in the Protection System Maintenance and Testing standard within the Reliability
Standards development process, and directed NERC to file, by July 30, 2012, either a completed
project, or an informational filing providing “a schedule for how NERC will address such issues
in the Project 2007-17 reinitiated efforts.” 2
This informational filing is submitted in compliance with Order No. 758. On May 10,
2012, the NERC Standards Committee approved a Standard Authorization Request to revise
Reliability Standard PRC-005 to address the maintenance and testing of reclosing relays in
NERC Project 2007-17.
The NERC Standards Committee noted that PRC-005-2 is in the final stages of the
development process, having passed successive ballot with 79 percent approval on June 27,
2012. NERC staff anticipates that PRC-005-2 will be presented for approval at the November
NERC Board of Trustees meeting. Therefore, in recognition of the consensus that has been
reached, the NERC Standards Committee determined that the drafting team should complete
work on PRC-005-2 currently under development and immediately thereafter begin work on the
necessary revisions to address reclosing relays, which would be reflected in a to be proposed
PRC-005-3.
1
2
Interpretation of Protection System Reliability Standard, 138 FERC ¶ 61,094 (2012), (“Order No. 758”).
Order No. 758 at fn 37.
The revised schedule for Project 2007-17 is provided herein as Attachment A. NERC
intends to proceed in accordance with the Project 2007-17 schedule.
Sincerely,
/s/ Willie L. Phillips
Willie L. Phillips
Attorney
North American Electric Reliability Corporation
cc:
Gerald W. Cauley, NERC President and Chief Executive Officer
Charles A. Berardesco, NERC Senior Vice President and General Counsel
Holly A. Hawkins, NERC Assistant General Counsel
Official service lists in Docket No. RM10-5-000
ATTACHMENT A
NERC Proposed Project 2007-17 Schedule to
Revise Reliability Standard PRC-005 to Address the Maintenance and
Testing of Reclosing Relays in Compliance with Order No. 758
January 2013
Standard Drafting Team continues work revising PRC-005
standard to address reclosing relays
April-May 2013
Initial draft PRC-005 standard posted for industry
comment
July-August 2013
Revised draft PRC-005 standard posted for industry
comment and initial ballot
October-November 2013
Revised PRC-005 standard posted for successive ballot
January 2014
Revised PRC-005 standard posted for successive ballot
March 2014
Revised PRC-005 standard posted for recirculation ballot
May 2014
Proposed PRC-005 standard submitted for NERC Board of
Trustees approval
July 2014
Petition for approval of PRC-005 filed with FERC
Considerations for
Maintenance and Testing of
Autoreclosing Schemes
System Analysis and Modeling Subcommittee
System Protection and Control Subcommittee
November 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC’s Mission
NERC’s Mission
The North American Electric Reliability Corporation (NERC) is an international regulatory
authority established to enhance the reliability of the bulk power system in North America.
NERC develops and enforces Reliability Standards; assesses adequacy annually via a ten‐year
forecast and winter and summer forecasts; monitors the bulk power system; and educates,
trains, and certifies industry personnel. NERC is the electric reliability organization for North
America, subject to oversight by the U.S. Federal Energy Regulatory Commission (FERC) and
governmental authorities in Canada.1
NERC assesses and reports on the reliability and adequacy of the North American bulk power
system, which is divided into eight Regional areas, as shown on the map and table below. The
users, owners, and operators of the bulk power system within these areas account for virtually
all the electricity supplied in the U.S., Canada, and a portion of Baja California Norte, México.
NERC Regional Entities
Note: The highlighted area between SPP RE and
SERC denotes overlapping Regional area
boundaries. For example, some load serving
entities participate in one Region and their
associated transmission owner/operators in
another.
FRCC
Florida Reliability
Coordinating Council
SERC
SERC Reliability Corporation
MRO
Midwest Reliability
Organization
SPP RE
Southwest Power Pool
Regional Entity
NPCC
Northeast Power
Coordinating Council
TRE
Texas Reliability Entity
RFC
ReliabilityFirst Corporation
WECC
Western Electricity
Coordinating Council
1
As of June 18, 2007, the U.S. Federal Energy Regulatory Commission (FERC) granted NERC the legal authority to enforce Reliability Standards
with all U.S. users, owners, and operators of the bulk power system, and made compliance with those standards mandatory and enforceable.
In Canada, NERC presently has memorandums of understanding in place with provincial authorities in Ontario, New Brunswick, Nova Scotia,
Québec, and Saskatchewan, and with the Canadian National Energy Board. NERC standards are mandatory and enforceable in Ontario and
New Brunswick as a matter of provincial law. NERC has an agreement with Manitoba Hydro making reliability standards mandatory for that
entity, and Manitoba has recently adopted legislation setting out a framework for standards to become mandatory for users, owners, and
operators in the province. In addition, NERC has been designated as the “electric reliability organization” under Alberta’s Transportation
Regulation, and certain reliability standards have been approved in that jurisdiction; others are pending. NERC and NPCC have been
recognized as standards‐setting bodies by the Régie de l’énergie of Québec, and Québec has the framework in place for reliability standards
to become mandatory. NERC’s reliability standards are also mandatory in Nova Scotia and British Columbia. NERC is working with the other
governmental authorities in Canada to achieve equivalent recognition.
Considerations for Maintenance and Testing of Autoreclosing Schemes
i
Table of Contents
Table of Contents
NERC’s Mission ................................................................................................................................. i
Table of Contents ............................................................................................................................ iii
Introduction .................................................................................................................................... 1
Considerations for Applicability of PRC‐005 ................................................................................... 2
Applications to Improve Bulk Power System Performance ........................................................ 2
Applications to Aid Restoration .................................................................................................. 3
Maintenance Intervals and Activities ............................................................................................. 8
Autoreclosing Relays ................................................................................................................... 8
Autoreclosing Control Circuitry .................................................................................................. 8
Recommendations ........................................................................................................................ 10
Appendix A – System Analysis and Modeling Subcommittee Roster ........................................... 11
Appendix B – System Protection and Control Subcommittee Roster .......................................... 12
This technical document was approved by the NERC Planning Committee on November 14, 2012.
Considerations for Maintenance and Testing of Autoreclosing Schemes
iii
Chapter 1 — Introduction
Introduction
On February 3, 2012, the Federal Energy Regulatory Commission (FERC) issued Order No. 7582
approving an interpretation of NERC Reliability Standard PRC‐005‐1, Transmission and
Generation Protection System Maintenance and Testing. In addition to approving the
interpretation, the Commission directed that concerns identified in the preceding Notice of
Proposed Rulemaking (NOPR) be addressed within the reinitiated PRC‐005 revisions.
The concerns raised in the NOPR pertain to automatic reclosing (autoreclosing) relays that are
either “used in coordination with a Protection System to achieve or meet system performance
requirements established in other Commission‐approved Reliability Standards, or can
exacerbate fault conditions when not properly maintained and coordinated,” in which case
“excluding the maintenance and testing of these reclosing relays will result in a gap in the
maintenance and testing of relays affecting the reliability of the Bulk‐Power System.”3 To
address these concerns, the Commission concludes that “specific requirements or selection
criteria should be used to identify reclosing relays that affect the reliability of the Bulk‐Power
System.”4
This report provides technical input from the NERC System Analysis and Modeling
Subcommittee (SAMS) and the System Protection and Control Subcommittee (SPCS), both
subcommittees of the NERC Planning Committee, to support the Project 2007‐17 standard
drafting team assigned to modify PRC‐005. This report recommends technical bases to identify
those autoreclosing applications that may affect reliability of the bulk power system. Such
applications should be included in the Applicability section of PRC‐005 to address the directives
in Order No. 758.
2
See FERC Order No. 758, Interpretation of Protection System Reliability Standard, 138 FERC ¶ 61,094.
3
Id. at P. 16.
4
Id. at P. 26.
Considerations for Maintenance and Testing of Autoreclosing Schemes
1
Chapter 2 — Considerations for Applicability of PRC‐005
Considerations for Applicability of PRC-005
Autoreclosing is utilized on transmission systems to restore transmission elements to service
following automatic circuit breaker tripping. When an autoreclosing application may affect
reliability of the bulk power system, the autoreclosing relay5 should be included in the
applicability of PRC‐005.
The concerns identified by the Commission in Order No. 758 can be grouped into two
categories:
situations in which autoreclosing fails to operate when required to maintain bulk power
system reliability; and
situations in which autoreclosing operates in manner that is not consistent with its
design, adversely affecting reliability of the bulk power system.
The following sections address these two categories of concern.
Applications to Improve Bulk Power System Performance
Consideration of Autoreclosing to Increase Operating Limits
Planning and operation of the bulk power system must consider autoreclosing applications.6
Autoreclosing following automatic circuit breaker tripping may be successful if the condition
that initiated the tripping (e.g., a fault) is no longer present, or it may be unsuccessful if the
condition is still present in which case the circuit breaker will trip again. While successful
autoreclosing enhances reliability of the bulk power system, autoreclosing into a permanent
fault may adversely affect reliability. Since the potential for autoreclosing into a permanent
fault exists for any application, it is not possible to depend on successful autoreclosing as a
means to meet the system performance requirements in the NERC Reliability Standards or to
increase the transfer limit associated with an Interconnection Reliability Operating Limit7
(IROL).
Single‐pole tripping and autoreclosing also may be used to minimize the impact to the system
for a single‐phase fault; however, the same issues exist for single‐pole autoreclosing with
regard to the potential for an autoreclose into a permanent fault after which all three poles are
tripped. In the event an autoreclosing relay fails to initiate reclosing after a single‐pole trip,
protective functions will detect the condition and trip all three poles after a time delay.
SAMS and SPCS have not identified an application in which autoreclosing is used in coordination
with a protection system to meet the system performance requirements in a NERC Reliability
5
Autoreclosing relays in this context include dedicated autoreclosing relays and the autoreclosing function in multi‐function relays.
6
For example, TPL‐001‐2, adopted by the NERC Board of Trustees on August 4, 2011, requires that analyses include the impact of subsequent
successful high‐speed autoreclosing and unsuccessful high‐speed autoreclosing into a fault where high‐speed autoreclosing is utilized.
7
Capitalized as referenced in the NERC Glossary of Terms.
2
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
Standard or in establishing an IROL. As discussed above, the need to consider autoreclosing
into a permanent fault precludes dependency on autoreclosing for this purpose. SAMS and
SPCS therefore recommend that no modification is necessary to the applicability of PRC‐005 to
address autoreclosing applications necessary for bulk power system performance.
Autoreclosing as Part of a Special Protection System
Special Protection Systems8 (SPS) may be applied to meet system performance requirements in
the NERC Reliability Standards or to increase the transfer limit associated with an IROL. When
autoreclosing is included as an integral part of such a SPS, a failure of the reclosing function
may adversely impact bulk power system reliability. NERC Reliability Standard PRC‐005‐29
includes minimum maintenance activities and maximum intervals for SPS. SAMS and SPCS
recommend that PRC‐005 be modified to explicitly address maintenance and testing of
autoreclosing relays applied as an integral part of a SPS.
Applications to Aid Restoration
Autoreclosing typically is installed to alleviate the burden on operators of manually restoring
transmission lines. Autoreclosing also provides improved availability of overhead transmission
lines. The degree to which availability is improved depends on the nature of the fault
(permanent or temporary) and on transmission operator practices for manually restoring lines.
While faster restoration of transmission lines following temporary faults does provide an
inherent reliability benefit, this section addresses applications that are not necessary to meet
system performance requirements in NERC Reliability Standards. In these applications it is
possible for undesired operation of the autoreclosing scheme, not consistent with its design, to
adversely affect system reliability. The following sections discuss credible failure modes that
may lead to undesired operation and the associated potential reliability impacts to the bulk
power system, to identify applications that should be included in the Applicability section of
PRC‐005.
Credible Failure Modes of Autoreclosing Schemes
This section discusses credible failure modes of autoreclosing schemes. These failure modes
are assessed in the next section to identify which may impact reliability of the bulk power
system. Applications for which one or more of these failure modes could adversely affect
reliability will be provided to the Project 2007‐17 standard drafting team to support
development of revisions to PRC‐005 directed in Order No. 758.
There are many different types of autoreclosing relays. Autoreclosing relays may be
electromechanical (and comprised of discrete components), solid state, or microprocessor‐
based and may be applied in a variety of autoreclosing schemes. Regardless of the type of
autoreclosing scheme or vintage of design of the autoreclosing relay, there are a few main
characteristics shared by most autoreclosing relays. These include:
8
Capitalized as referenced in the NERC Glossary of Terms.
9
PRC‐005‐2 achieved 81.08 percent quorum and 80.51 percent approval in a recirculation ballot that ended October 24, 2012.
Considerations for Maintenance and Testing of Autoreclosing Schemes
3
Chapter 2 — Considerations for Applicability of PRC‐005
Supervision Functions: Supervising elements typically monitor one or more voltage
phases to determine if a circuit is energized (live), de‐energized (dead), or in
synchronism with another circuit, etc. Other types of supervision may be used to
perform selective autoreclosing; e.g., autoreclosing is blocked for the detection of a
three‐phase fault, or for the loss of a communication channel. In some applications,
autoreclosing is unsupervised.
Timing Functions: Timing elements perform various timing duties with the most
important being the desired time delay to issue a circuit breaker close; the minimum
time delay being dictated by de‐ionization time. In some applications, autoreclosing is
initiated by protective relaying and issues a close signal with little or no intentional time
delay.
Output Function: The output function is typically some type of relay with contacts that
close and apply DC voltage to the close circuit to effect a circuit breaker close.
When analyzing autoreclosing relay failure modes, the functions described above are the ones
most likely to lead to a failure. The failures can be analyzed without a detailed discussion of the
many variations of autoreclosing logic that may be implemented throughout North America.
The main failure modes of autoreclosing relays are:
Supervision Function Failures: A failed voltage supervision function that requires a dead
line to reclose may incorrectly interpret that the monitored circuit is live and
consequently not issue a close signal to a circuit breaker as designed. Conversely, a
failed voltage supervision function that requires a live line to reclose may incorrectly
interpret that a dead circuit is live and, therefore, incorrectly issue a close signal to a
circuit breaker. Further, failure of a synchronism check function may allow a close when
static system angles are greater than designed, or inhibit a close when static system
angles are less than designed.
Timing Function Failures: Where intentional time delays are used, the time delay circuits
may fail and issue a close with no time delay. Failure of the time delay circuits may also
inhibit the autoreclosing relay from issuing a close signal.
Output Function Failures: The output relay contacts may fail to close and thus no close
signal will be issued to a circuit breaker. The output relay contacts may also fail in the
closed position (“weld shut”) and send a constant close signal to a circuit breaker. Solid
state outputs can exhibit both of these failure modes. This failure mode can result in
one of two possible scenarios depending on the circuit breaker closing circuit design and
whether the constant close signal occurs prior to tripping or during the act of reclosing
the circuit breaker. One scenario is that no reclose will occur. The second scenario will
result in only one reclose being attempted.
Thus, to assess the potential impact of an autoreclosing relay failure on the power system, the
following types of failures should be considered:
4
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
No close signal is issued under conditions that meet the intended design conditions.
This is the most common failure mode and includes the vast majority of autoreclosing
failures.
A close signal is issued with no time delay or with less time delay than is intended.
A constant or sustained close signal is issued. In this case, a multi‐shot reclose scheme
may attempt to reclose only once.
A close signal is issued for conditions other than the intended supervisory conditions.
Potential Reliability Impacts
In this section each of the identified autoreclosing failure modes is analyzed to assess the
potential for adverse impact to bulk power system reliability and the circumstances under
which impacts may occur.
1. No close signal is issued under conditions that meet the intended design conditions: A
failure to autoreclose would result in a failure to restore a single power system element.
The system already must be planned and operated considering that autoreclosing will be
unsuccessful. Thus, the impact to power system reliability for this failure mode results in a
condition the system is designed to withstand, and therefore this failure mode does not
create any additional considerations for inclusion of autoreclosing relays in PRC‐005 beyond
those related to SPS as discussed in the previous section.
2. A close signal is issued with no time delay or with less time delay than is intended: This
failure mode can result in a minimum trip‐close‐trip sequence with the two faults cleared in
primary protection operating time, and the open time between faults equal to the breaker
closing cycle time. The sequence for this failure mode results in system impact equivalent
to a high‐speed autoreclosing sequence with no delay added in the autoreclosing logic.
The potential reliability impacts of this failure mode are damage to generators and
generator instability. Autoreclosing logic typically is selected to reenergize a dead circuit
remote from generating units or strong sources to avoid adverse impacts associated with
autoreclosing into a permanent fault. Typically when autoreclosing is applied at a
generating station it is only for live‐line conditions with synchronism check; however,
applications do exist where autoreclosing from a generating station is used such as
transmission lines between two generating plants, or radial lines that cannot be energized
from another source. Where autoreclosing is applied at or in proximity to a generating
station the potential for this failure mode exists.
Premature autoreclosing has the potential to cause generating unit loss of life due to shaft
fatigue. Accepted industry guidance is that planned switching operations, such as simple
line restoration, should be conducted in a way that avoids significant contribution to
cumulative shaft fatigue. Entities typically implement this guidance at generating stations
by using time delayed autoreclosing to allow shaft oscillations to dampen, and/or live line
autoreclosing or live bus‐live line autoreclosing with synchronism check supervision to
Considerations for Maintenance and Testing of Autoreclosing Schemes
5
Chapter 2 — Considerations for Applicability of PRC‐005
minimize shaft torque. By conducting planned switching in this manner, nearly all of the
fatigue capability of the shaft is preserved to withstand the impact of unplanned and
unavoidable disturbances such as faults, fault clearing, reclosing into system faults, and
emergency line switching. Premature autoreclosing due to a supervision failure is a small
subset of autoreclosing failures (the overwhelming majority of autoreclosing failures are
failure to close) and is an infrequent unplanned disturbance. As a result, it is not necessary
to consider the incremental loss of life that may occur for this infrequent event as the basis
for whether to include maintenance and testing of autoreclosing relays in PRC‐005.
Premature autoreclosing also has the potential to cause generating unit or plant instability.
NERC Reliability Standards require consideration of loss of the largest generating unit within
a Balancing Authority Area10; therefore, generation loss would not impact reliability of the
bulk power system unless the combined capacity loss exceeds the largest unit within the
Balancing Authority Area. Including maintenance and testing of autoreclosing relays in PRC‐
005 would therefore be appropriate for applications at or in proximity to generating plants
with capacity exceeding the largest unit within the Balancing Authority Area. In this context
proximity is defined as one bus away if the bus is within 10 miles of the generating plant.
Transmission line impedance on the order of 1 mile away typically provides adequate
impedance to prevent generating unit instability and a 10 mile threshold provides sufficient
margin.
At these locations, maintenance and testing of autoreclosing relays should be subject to
PRC‐005, unless the equipment owner can demonstrate to the Transmission Planner that
this failure mode would not result in tripping generating units with combined capacity
greater than the largest unit within the Balancing Authority Area. This demonstration
should be based on simulation of a close‐in three‐phase fault for twice the normal clearing
time (capturing a minimum trip‐close‐trip time delay).
3. A constant or sustained close signal is issued: This failure mode can result in one of two
possible scenarios depending on the circuit breaker closing circuit design and whether the
constant close signal occurs prior to tripping or during the act of reclosing the circuit
breaker. One scenario is that no reclose will occur. The second scenario will result in only
one reclose being attempted. This scenario results in the worse impact; however this
results in an outcome similar to failure mode No. 1 – less reclose attempts than planned.
Neither of these failure modes creates any additional considerations for inclusion of
autoreclosing relays in PRC‐005.
4. A close signal is issued for conditions other than the intended supervisory conditions: This
failure mode can result in two different scenarios.
The first scenario is autoreclosing into a dead line with a fault when dead‐line closing was
not intended. Similar to failure mode No. 2 discussed above, the potential reliability
10
Capitalized as referenced in the NERC Glossary of Terms.
6
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 2 — Considerations for Applicability of PRC‐005
impacts of this failure mode are instability and damage to generating units. The incidence
of this failure mode is similar to failure mode No. 2 and therefore concern may be limited to
the potential loss of generating units with combined capacity that exceeds the largest unit
within the Balancing Authority Area. Including maintenance and testing of autoreclosing
relays in PRC‐005 would therefore be appropriate for applications at or in proximity to
generating units as noted above. The primary difference between this scenario and failure
mode No. 2 is this failure mode does not include a timing failure. As such both this scenario
and failure mode No. 2 can lead to unintended autoreclosing into fault; however, the timing
of the undesired autoreclosure in this scenario will occur after any intentional time delay
included in the autoreclosing relay. For this reason a separate test is not necessary to
exclude applications from maintenance and testing under PRC‐005. Application of the test
described for failure mode No. 2 adequately addresses this failure mode.
The second scenario is autoreclosing into a live line with an angle greater than the
acceptance angle necessary to prevent potential equipment damage. The potential
reliability impact of this failure mode is damage to generating units. As noted in the
discussion of failure mode No. 2, accepted industry guidance is that planned switching
operations, such as simple line restoration, should be conducted in a way that avoids
significant contribution to cumulative shaft fatigue. By conducting planned switching in this
manner, nearly all of the fatigue capability of the shaft is preserved to withstand the impact
of unplanned and unavoidable disturbances such as faults, fault clearing, reclosing into
system faults, and emergency line switching. Undesired autoreclosing at an angle greater
than the sync‐check acceptance angle due to a supervision failure is a small subset of
autoreclosing failures and is an infrequent unplanned disturbance. As a result, it is not
necessary to consider the incremental loss of life that may occur for this infrequent event as
the basis for whether to include maintenance and testing of autoreclosing relays in PRC‐
005.
Considerations for Maintenance and Testing of Autoreclosing Schemes
7
Chapter 3 — Maintenance Intervals and Activities
Maintenance Intervals and Activities
The SPCS reviewed the maximum maintenance intervals and minimum maintenance activities
proposed in reliability standard PRC‐005‐2. Specifically, the SPCS reviewed Table 1‐1 which is
applicable to protective relays and Table 1‐5 which is applicable to control circuitry associated
with protective functions (excluding distributed UFLS and distributed UVLS). The SPCS review
focused on whether any substantive differences exist between protective relays and
autoreclosing relays, or between control circuitry associated with protective functions and
circuitry associated with autoreclosing schemes, that would warrant different intervals or
activities for maintenance of autoreclosing components.
Autoreclosing Relays
The SPCS concluded that electromechanical, solid‐state, and microprocessor based
autoreclosing relays are substantially the same with respect to design and manufacturing as
their protective relay counterparts. As such, the SPCS recommends that the maximum intervals
defined in Table 1‐1 of PRC‐005‐2 should also be applicable to autoreclosing relays that may be
subject to future versions of the standard.
The SPCS also assessed the maintenance activities included in Table 1‐1 of PRC‐005‐2 and
concluded that the activities are analogous to activities performed during maintenance and
testing of autoreclosing relays and therefore Table 1‐1 should be applied to autoreclosing relays
that may be subject to future versions of the standard. For example, the activity to test and, if
necessary calibrate, non‐microprocessor relays would be applicable to testing and calibration of
electromechanical and solid‐state autoreclosing relays, and the activity to verify acceptable
measurement of power system input values would be applicable to verification of permissive
inputs used for voltage supervision and synchronism check.
Autoreclosing Control Circuitry
Similarly, the SPCS assessed the maintenance intervals and activities included in Table 1‐5 of
PRC‐005‐2 and concluded that the intervals and activities for maintaining control circuitry for
autoreclosing schemes should be similar to those established for maintaining control circuitry
associated with protective functions. The SPCS recommends that Table 1‐5 should be
applicable to control circuitry associated with autoreclosing relays that may be subject to future
versions of the standard. The SPCS also recommends that the standard drafting team include
minimum maintenance activities and maximum maintenance intervals for autoreclosing control
circuitry that parallel the maintenance activities and intervals established for protective
function control circuitry. It should be noted that, consistent with control circuitry defined for
protective functions, the SPCS does not consider internal breaker control circuitry (e.g., anti‐
pump and coil interlock circuits) to be associated with autoreclosing component maintenance.
Since the failure to close may represent a risk to reliability when breaker closing is integral to
operation of an SPS, the closing coil should be considered in PRC‐005. For use within a revision
to PRC‐005, control circuitry of autoreclosing schemes might be defined as:
8
Considerations for Maintenance and Testing of Autoreclosing Schemes
Chapter 3 — Maintenance intervals and Activities
“Control circuitry associated with autoreclosing schemes including the close coil, but
excluding breaker internal controls such as anti‐pump and various interlock circuits.”
Considerations for Maintenance and Testing of Autoreclosing Schemes
9
Chapter 4 — Recommendations
Recommendations
SAMS and SPCS recommend the following guidance for future development of NERC Reliability
Standard PRC‐005, Transmission and Generation Protection System Maintenance and Testing,
to address the concerns stated in FERC Order No. 758.
1. Modify PRC‐005 to explicitly address maintenance and testing of autoreclosing relays
applied as an integral part of a SPS.
2. Modify PRC‐005 to include maintenance and testing of autoreclosing relays at or in
proximity to generating plants at which the total installed capacity is greater than the
capacity of the largest generating unit within the Balancing Authority Area.
In this context, define proximity as substations one bus away if the substation is within
10 miles of the plant.
Include a provision to exclude autoreclosing relays if the equipment owner can
demonstrate to the Transmission Planner that a close‐in three‐phase fault for twice the
normal clearing time (capturing a minimum trip‐close‐trip time delay) does not result in
a total loss of generation in the interconnection exceeding the largest unit within the
Balancing Authority Area where the autoreclosing is applied.
3. Base minimum maintenance activities and maximum intervals on the activities and intervals
in PRC‐005‐2.
Develop minimum maintenance activities and maximum intervals for autoreclosing
relays similar to Table 1‐1.
Develop minimum maintenance activities and maximum intervals for control circuitry of
autoreclosing schemes similar to Table 1‐5.
For the purpose of PRC‐005, define control circuitry of autoreclosing schemes as:
“Control circuitry associated with autoreclosing schemes including the close coil, but
excluding breaker internal controls such as anti‐pump and various interlock circuits.”
10
Considerations for Maintenance and Testing of Autoreclosing Schemes
Appendix A – System Analysis and Modeling Subcommittee Roster
Appendix A – System Analysis and Modeling
Subcommittee Roster
John Simonelli
Chair
Director - Operations Support Services
ISO New England
Jonathan E. Hayes
RE – SPP
Reliability Standards Development Engineer
Southwest Power Pool, Inc.
K. R. Chakravarthi
Vice Chair
Manager, Interconnection and Special Studies
Southern Company Services, Inc.
Kenneth A. Donohoo
RE – TRE
Director System Planning
Oncor Electric Delivery
G. Brantley Tillis, P.E.
RE – FRCC
Manager, Transmission Planning Florida
Progress Energy Florida
Hari Singh
RE – WECC
Transmission Asset Management
Xcel Energy, Inc.
Kiko Barredo
RE – FRCC – Alternate
Manager, Bulk Transmission Planning
Florida Power & Light Co.
Kent Bolton
RE – WECC – Alternate
Staff Engineer
Western Electricity Coordinating Council
Thomas C. Mielnik
RE – MRO
Manager Electric System Planning
MidAmerican Energy Co.
Digaunto Chatterjee
ISO/RTO
Manager of Transmission Expansion Planning
Midwest ISO, Inc.
Salva R. Andiappan
RE – MRO – Alternate
Manager - Modeling and Reliability Assessments
Midwest Reliability Organization
Patricia E. Metro
Cooperative
Manager, Transmission and Reliability Standards
National Rural Electric Cooperative Association
Donal Kidney
RE – NPCC
Manager, System Compliance Program Implementation
Northeast Power Coordinating Council
Eric Mortenson, P.E.
Investor-Owned Utility
Principal Rates & Regulatory Specialist
Exelon Business Services Company
Bill Harm
RE – RFC
Senior Consultant
PJM Interconnection, L.L.C.
Amos Ang, P.E.
Investor-Owned Utility
Engineer, Transmission Interconnection Planning
Southern California Edison
Mark Byrd
RE – SERC
Manager - Transmission Planning
Progress Energy Carolinas
Greg Henry
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Gary T. Brownfield
RE – SERC – Alternate
Supervising Engineer, Transmission Planning
Ameren Services
Considerations for Maintenance and Testing of Autoreclosing Schemes
11
Appendix B – System Protection and Control Subcommittee Roster
Appendix B – System Protection and Control
Subcommittee Roster
William J. Miller
Chair
Principal Engineer
Exelon Corporation
Baj Agrawal
RE – WECC
Principal Engineer
Arizona Public Service Company
Philip B. Winston
Vice Chair
Chief Engineer, Protection and Control
Southern Company
Miroslav Kostic
Canada Provincial
P&C Planning Manager, Transmission
Hydro One Networks, Inc.
Michael Putt
RE – FRCC
Manager, Protection and Control Engineering Applications
Florida Power & Light Co.
Sungsoo Kim
Canada Provincial
Section Manager – Protections and Technical Compliance
Ontario Power Generation Inc.
Mark Gutzmann
RE – MRO
Manager, System Protection Engineering
Xcel Energy, Inc.
Michael J. McDonald
Investor-Owned Utility
Principal Engineer, System Protection
Ameren Services Company
Richard Quest
RE – MRO – Alternate
Principal Systems Protection Engineer
Midwest Reliability Organization
Jonathan Sykes
Investor-Owned Utility
Manager of System Protection
Pacific Gas and Electric Company
George Wegh
RE – NPCC
Manager
Northeast Utilities
Charles W. Rogers
Transmission Dependent Utility
Principal Engineer
Consumers Energy Co.
Jeff Iler
RE – RFC
Senior Engineer
American Electric Power
Joe T. Uchiyama
U.S. Federal
Senior Electrical Engineer
U.S. Bureau of Reclamation
Joe Spencer
RE – SERC -- Alternate
Manager of Planning and Engineering
SERC Reliability Corporation
Daniel McNeely
U.S. Federal – Alternate
Engineer - System Protection and Analysis
Tennessee Valley Authority
Lynn Schroeder
RE – SPP
Manager, Substation Protection and Control
Westar Energy
Philip J. Tatro
NERC Staff Coordinator
Senior Performance and Analysis Engineer
NERC
Samuel Francis
RE – TRE
System Protection Specialist
Oncor Electric Delivery
12
Considerations for Maintenance and Testing of Autoreclosing Schemes
Standards Announcement Correction
Project 2007-17.2: PRC-005-3 Protection System Maintenance and
Testing - Phase 2 (Reclosing Relays)
PRC-005-3 Formal Comment Period Open: April 5, 2013 – May 6, 2013
SAR Informal Comment Period Open: April 5, 2013 – May 6, 2013
Now Available
A Standard Authorization Request (SAR) for PRC-005 and draft of PRC-005-3 – Protection System and
Automatic Reclosing Maintenance are each posted for a 30-day comment period through 8 p.m.
Eastern on Monday, May 6, 2013.
This phase of the project is limited to addressing a regulatory directive from FERC Order No. 758. The
SAR is being posted for an informal comment period with no requirement for the standard drafting
team to provide a formal response. The standard is being posted for a formal comment period and a
formal response to those comments will be prepared.
Background information for this project can be found on the project page.
Instructions for Commenting
The comment period for the SAR and draft PRC-005-3 is open through 8 p.m. Eastern on Monday,
May 6, 2013. Please use the following electronic forms to submit comments:
Comment Form – SAR
Comment Form – PRC-005-3
If you experience any difficulties in using the electronic forms, please contact Wendy Muller at
[email protected]. An off-line, unofficial copy of each of the comment forms is posted on the
project page.
Next Steps
The drafting team will consider all comments and determine whether to make changes to the standard
and associated documents. After the standards and associated documents are revised, the drafting
team will submit the documents for a quality review and seek acceptance from the NERC Standards
Committee to proceed to balloting.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement – Project 2007-17.2
2
Name (12 Responses)
Organization (12 Responses)
Group Name (12 Responses)
Lead Contact (12 Responses)
Contact Organization (12 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (1 Responses)
Comments (24 Responses)
Question 1 (21 Responses)
Question 1 Comments (23 Responses)
Question 2 (20 Responses)
Question 2 Comments (23 Responses)
Question 3 (21 Responses)
Question 3 Comments (23 Responses)
Question 4 (0 Responses)
Question 4 Comments (23 Responses)
Dominion
Louis Slade
NERC Compliance Policy
No
The SAR goes beyond the directive in that it appears to indicate that all reclosing relays must
operate properly in order to maintain BES reliability. The fact is that, in a majority of
applications, these relays exist primarily to decrease outage times. The SAR should be limited
to only those reclosing relays whose failure to operate correctly could adversely impact
reliable operation of the BES. Dominion therefore recommends revising the sentence that
reads “The Applicability section of the Standard must be modified to describe explicitly those
devices that entities are to maintain in accordance with the revised standard.” To read “The
Applicability section of the Standard must be modified to describe explicitly those reclosing
relays that entities are to maintain in accordance with the revised standard.”
No
No
Having reviewed, and generally agree with, the technical study performed jointly by the NERC
System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) and subsequently approved by the NERC Planning Committee. We
therefore support the OPTIONAL approach shown near the bottom of the SAR as we believe
would revise the standard in a way that applies new requirements only to those elements of
the protection system where reclosing is applied it been demonstrated to that an adverse
impact on the BES could occur if those element(s) are not included in one or more reliability
standard requirements.
Duke Energy
Colby Bellville
Duke Energy
Yes
However we are concerned that the SAR includes possible revision of the definition of
Protection System. We don’t believe attempting to revise that definition is necessary or
advisable.
No
No
The SAR includes statements under “Goals” and “Detailed Description” that the defined term
Protection System might be revised as part of this project. Those statements should be
removed from the SAR. We strongly believe that the issue of maintenance and testing of any
reclosing relays which can affect reliable operation of the BES, can be addressed without
attempting to modify the definition of Protection System.
Nazra Gladu
Manitoba Hydro
Yes
No
No
(1) Brief Description of Proposed Standard Modifications/Actions - for completeness, add
‘(BES)’ after Bulk Electric System. (2) Need - capitalize ‘misoperation’ because it appears in the
Glossary of Terms. (3) Need - remove the words “Bulk Electric System” to leave only the
acronym, BES because this is the second instance of BES in the document.
John Bee
Exelon and its Affiliates
Yes
No
Yes
FirstEnergy
Larry Raczkowski
FirstEnergy Corp
Yes
No
No
FE supports the referenced SAR as stated.
Bill Fowler
City of Tallahassee
Yes
No
No
None
PacifiCorp
Ryan Millard
PacifiCorp
Yes
No
No
Chris Mattson
Tacoma Power
Yes
No
No
Thomas Foltz
American Electric Power
No
AEP supports the efforts of the drafting team, but is concerned by pursuing a version 3 of this
standard before the second version has been approved by FERC. There is significant content
within version 3 that was new to version 2, so proper implementation of version 3 would rely
on the eventual approval of version 2 in its entirety. The content of version 3 has apparently
been drafted with this in mind, however, it over-complicates the implementation plan of
version 3 by basing it in-part on the previous and not-yet-approved version, and leaving it
vulnerable in the event version 2 does not pass. In addition, it is not clear exactly which sort of
automatic reclosing behavior(s) the proposed changes are attempting to prevent. Accidental
reclosing? Failure to reclose? Providing clarity on this fundamental question will help industry
in providing sound comments and feedback regarding PRC-005-3.
No
AEP is not aware of any regional variances that would be needed as a result of this project.
Yes
AEP believes that it is likely that some of its business practices would need to at least be
modified as a result of this project
Pepco Holdings Inc & Affiliates
David Thorne
Pepco Holdings Inc
Yes
No
No
Brad Harris
CenterPoint Energy
Yes
Business practices will be needed to: 1. Document and monitor the generating plant capacity
at all Company owned generation interconnection facilities 2. Document and monitor the
largest generating unit located in the Balancing Authority 3. Document and monitor the
Company owned stations meeting the Applicability attributes described in 4.2.6 of PRC-005-3.
Page 2, Paragraph 2 of the “Need” section of the SAR includes a parenthetical “(installed to
meet performance goals of approved NERC Standards)”. Recommend deleting this
parenthetical statement as the SAMS/SPCS paper concluded on page 2 that “SAMS and SPCS
have not identified an application in which auto reclosing is used in coordination with a
protection system to meet the system performance requirements in a NERC Reliability
Standard or in establishing an IROL”.
Kenn Backholm
Public Utility District No.1 of Snohomish County
Yes
No
No
The Public Utility District No.1 of Snohomish County has reviewed and supports this Standard
Authorization Request and concluded that the revisions and modifications do not seem
impractical or technically unreasonable.
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
Yes
No
No
None
Andrew Z. Pusztai
American Transmission Company
Yes
No
No
Southern Company: Southern Company Services, Inc; Alabama Power Company; Georgia
Power Company; Gulf Power Company; Mississippi Power Company; Southern Company
Generation; Southern Company Generation and Energy Marketing
Marcus Pelt
Southern Company Operations Compliance
Yes
No
No
It seems out of order to be posting a draft SAR for informal comment at the same time that
the revised standard which is the topic of the SAR is posted for a formal comment period.
Further, FERC has not approved PRC-005-2 yet. Any changes required by FERC would affect
the draft of PRC-005-3. The proposed standard modification seems premature given that PRC005-3 SAR is still in draft that PRC-005-2 is not yet approved.
Anthony Jablonski
ReliabilityFirst
No
No, the scope of the SAR only lists three bullet items. It should as a minimum include a lead in
sentence similar to the following: PRC-005-2 has been revised to include the maintenance and
testing of reclosing relays that can affect the reliable operation of the Bulk Power System. The
bullet items do not include the changes made to the Definitions of Terms, Requirements or
Compliance sections.
No
No
Can the SDT clarify whether high-speed automatic reclosing is covered within the scope of the
SAR?
Tennessee Valley Authority
Brandy Spraker
Transmission Reliability Engineering and Controls
1. Are reclosing relays considered "protective relays"? 2. Are reclosing relays considered part
of the "protective system"? 3. Is Table 1-3 applicable to CCVTs that feed only reclosing relays?
4. Does a "reclosing relay" include all relays used to perform all type of automatic reclosing
actions, i.e. sync check, dead line, dead bus, and blind reclosing?
Kevin Luke
Georgia Transmission Corporation
Agree
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
Yes
No
Yes
Jonathan Meyer
Idaho Power Company
Yes
No
No
ACES Standards Collaborators
Jason Marshall
ACES
Yes
(1) While we agree the SAR addresses the regulatory directive,we question the value of
modifying this standard further when the newest version has yet to be approved. If FERC
issues significant directives, the directives could ultimately impact the direction that drafting
team should take with modifying the standard to include reclosing relays. Furthermore,
because PRC-005 is historically one of the most violated standards primarily because of the
zero-defect approach to compliance, we question the value of adding another relay type to
the list of relays subject to zero-defect compliance. We are concerned there will be another
step function in potential violations that do not ultimately support reliability but detract from
reliability because they are focused on documentation. (2) We believe that there are other
equally-effective options to address the FERC directives, such as issuing an industry guidance
document. If the standard ultimately needs to be modified, a guidance document could allow
the drafting team to wait until FERC rules on the PRC-005 to determine if there will be any
impacts on adding reclosing relays to the standard.
No
No
(1) We understand that NERC is obligated by law to address all FERC directives issued to them.
However, not all FERC directives require the development or revision of a reliability standard.
FERC has been clear that other alternatives may be used as long as they are equally effective
and efficient. NERC and the drafting team need to consider other alternatives that would
produce an equally effective method of ensuring that auto-reclosing relays will be maintained
and tested. The drafting team should consider a survey of all registered entities subject to the
current PRC-005 standard to see if they include auto-reclosers in their PSMT program. This
issue goes back to compliance – whether the entity needs to maintain documentation for
each of these devices. A guidance document may be an appropriate solution to handle this
FERC directive. (2) Thank you for the opportunity to comment.
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
Scott Langston
City of Tallahassee
Yes
No
No
None
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program
Yes
No
No
Name (20 Responses)
Organization (20 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
Contact Organization (16 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING
ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (1 Responses)
Comments (36 Responses)
Question 1 (33 Responses)
Question 1 Comments (35 Responses)
Question 2 (33 Responses)
Question 2 Comments (35 Responses)
Dominion
Louis Slade
NERC Compliance Policy
No
Dominion agrees with most points and conceptually supports the SDT effort to limit additional
applicability of this to those facilities identified in the Considerations for Maintenance and
Testing of Autoreclosing Schemes report. We are however concerned that footnote 1 requires
the “equipment owner can demonstrate that a close-in three-phase fault present for twice the
normal clearing time (capturing a minimum trip close- trip time delay) does not result in a total
loss of generation in the Interconnection exceeding the largest unit within the Balancing
Authority Area where the Automatic Reclosing is applied.” We do not believe that most
Distribution Providers or Generator Owners have access to the information, or staff with
necessary skills to make such assessments. In fact, we are not confident that entities with such
access and skilled staff can make such as assertion. At best we believe an entity with the
necessary access and skills could perform an analysis and indicate whether acceptable voltages,
flows, angles and stability would be adversely impacted by incorrect operation of an Automatic
Reclosing. We do not believe such entity could determine whether or not an incorrect
operation would “….result in a total loss of generation in the Interconnection exceeding the
largest unit within the Balancing Authority Area where the Automatic Reclosing is applied.” We
therefore conceptually support most of the standard but request the SDT consider adding a
requirement that the Transmission Planner provide a list of those facilities where incorrect
operation of Automatic Reclosing has been shown to result in such loss or alternatively to
identify facilities where incorrect operation could be shown to result in violation of IROLs.
No
The implementation plan should utilize Transmission Planner (TP) notification to applicable
entities rather than simply base the plan on the regulatory approval date to start the
implementation timelines. This would allow the notified entities to have the same amount of
time that is currently in the implementation plan upon notification from the Transmission
Planner.
Doug Jensen
Vandolah Power Company
Yes
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
Yes
Would misoperations of automatic reclosing relays as specified in 4.2.6 have to be reported in
PRC-004-2?
Yes
Herb Schrayshuen
Self
Yes
No
It will take longer than the team suggests. Suggest a survey to determine a date the industry
can adhere to, if a survey has not been performed yet.
David Ramkalawan
OPG
Yes
Yes
Michelle R. D'Antuono
Ingleside Cogeneration LP (Occidental Chemical Corporation)
No
Ingleside Cogeneration LP is generally supportive of the changes that the drafting team has
made to PRC-005-2 and supporting documentation to address FERC Order 758. First and
foremost, we agree that the definition of “Protection System” should not be modified as it has
implications to any standard that uses the term. This far exceeds the scope of FERC’s directive
– which only identifies recloser maintenance as a reliability imperative. Second, we believe that
the underlying technical basis for the identification of recloser relays that “can affect the
reliability” of the BES is sound. The analysis performed by NERC’s System Analysis and
Modeling and System Protection and Control Subcommittees (SAMS-SPCS) is compelling in our
view. In this manner, the industry and CEAs can focus on those components which may pose
risk to the local system – and not expend resources on those which do nothing to improve
electric service delivery. However, as a Generator Owner, we are not sure how we will capture
the information we need to conduct an analysis of our recloser relays. We can approach our
Balancing Authority to have them provide the “capacity of the largest generating unit” within
their control area – but have no recourse if they refuse to respond due to security or anticompetitive reasons. Even if this is not an issue, it seems plausible that an extended outage of
the BA’s largest generator may re-set PRC-005-3’s applicability threshold downward. If this
happens, we may be required to re-evaluate our equipment base on a moment’s notice. We
don’t believe it is the drafting team’s intent to establish thresholds which may change in this
manner. It would be far simpler if an Interconnect-wide capacity threshold could be
established within PRC-005-3. Those Balancing Authorities that require a lower threshold could
communicate their expectations to their base as they see fit.
Yes
Nazra Gladu
Manitoba Hydro
No
(1) Definition of Terms Used in Standard - statements in this section are contradictory. Please
clarify if “When the standard becomes effective, these defined terms will be removed from the
individual standard and added to the Glossary.” or whether “The following terms are defined
for use only within PRC-005-3, and should remain with the standard upon approval rather than
being moved to the Glossary of Terms.” Why are the following terms defined for use only
within PRC-005-3 rather than being moved to the Glossary of Terms? (Automatic Reclosing,
Unresolved Maintenance Issue, Segment, Component Type, Component and Countable Event).
(2) Definitions of Terms Used in Standard, Protection System Maintenance Program (PSMP)
(NERC Board of Trustees Approved Definition) - for clarity, the word ‘is’ in the following
sentence, “…components is restored.” should be changed to “…components are restored.”
Additionally, MH assumes that the words “NERC Board of Trustees Approved Definition” will be
removed from the final version of the standard and that wording was provided for
informational purposes only in the circulation of the standard. (3) Definitions of Terms Used in
Standard, Automatic Reclosing - for clarity, we suggest beginning the definition with the
following words ‘includes the following’. (4) Definitions of Terms Used in Standard, Segment please clarify if the reference to Components in this definition is intended to be to the defined
term “Components”? If so, the word should be capitalized at the end of this definition. If this is
not the intension, then an alternate word should be chosen to avoid confusion. (5) Definitions
of Terms Used in Standard, Countable Event - the words “included in” from the last sentence of
the definition are unnecessary and should be removed. (6) A. Introduction, 3. Purpose - for
clarity, consider revising the purpose to read “To document and implement programs for the
maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) for maintaining functional operation”. (7) 4.2.6 Automatic Reclosing for section consistency, the words ‘applied on BES Elements, including:’ should be added to
4.2.6. Additionally, sections 4.2.6.1 and 4.2.6.2 should be rewritten as follows: 4.2.6.1
“Automatic Reclosing Applied on BES Elements at generating plant substations….” 4.2.6.2
“Automatic Reclosing Applied on BES Elements at substations….” (8) 4.2 footnote 1 – reference
is made to equipment owner which is an undefined term. For clarity, consider referring to the
Responsible Entity instead. In addition, some words seem to be missing which could provide
some guidance as to what is being compared. For example, is it the intent of meaning - “does
not result in a total loss of generation in the Interconnection exceeding the generation of the
largest unit within the Balancing Authority Area….”? (9) 4.2.6.3 – the words ‘integral part’ are
very subjective and may be difficult to assess. (10) 5. Effective Date - for completeness and
consistency with other standards, text from the implementation plan should be moved to the
standard Effective Date section. (11) 3. Measures - use the acronym for Protection System
Maintenance Program, PSMP in M1 and M4 since this is not the first instance of this definition.
(12) 1.3. Evidence Retention - use the acronym for Protection System Maintenance Program,
PSMP in the third paragraph of this section because this is not the first instance of this
definition. (13) PRC-005 - Attachment A, Criteria for a Performance-Based Protection System
Maintenance Program - for completeness, add the acronym (PSMP) after the title. (14) Section
D, Compliance, 1.1 – the paraphrased definition of ‘Compliance Enforcement Authority’ from
the Rules of Procedure is not the standard language for this section. Is there a reason that the
standard CEA language is not being used? (15) Section D, Compliance, 1.3 – this section was
not updated to reference Automatic Reclosing. (16) Protection System Maintenance Program is
defined in the standard as PMSP but then inconsistently referenced using both the full term
and the acronym. (17) R1 – there are inconsistent references throughout the requirements
made to ‘Protection System and Automatic Closing Component Types’ vs. ‘Protection System
Component Type and Automatic Reclosing Components’ vs. ‘Protection System and Automatic
Reclosing Components’. Please clarify if this is the intent or consider correcting. (18) R2, R3 and
R4 – there appears to be inconsistency in the drafting of R1, R2 and R3 as to what is required.
There is no requirement to “implement and follow” a PMSP within the time based program the
way there is for the performance based program. (19) R5 – MH believes that the requirement
should be to make efforts, not demonstrate efforts. Demonstrating or providing evidence of
the efforts would be the measure. (20) VSLs, R1 – the Requirement refers to both Protection
System and Automatic Reclosing Components while the VSL refers only to Components. (21)
VSLS, R2 – the wording of the VSL for this requirement does not seem consistent with the
wording of Attachment A. (22) VSLS, R3 and R4 – rather than writing ‘more than x% but y% or
less’, it would be clearer to write ‘more than x% but less than y%’.
No
(23) General - use the acronyms for “Protection System Maintenance Program”, PSMP and for
“Board of Trustees”, BOT. Both terms are referenced multiple times within the Implementation
Plan document.
John Bee
exelon and its Affiliates
No
We understand the concerns related to reclosing relays however we do not agree that these
devises should be included in PRC-005 because reclosing relay are not a protective device. The
current system stability studies do not rely on automatic reclosing to maintain the reliability of
the Bulk Power System.
No
1. 4.2.6.1 – How would a PRC-005-3 relay engineer determine or be made aware of “the
capacity of the largest generating unit within the Balancing Authority Area” at any given
moment in time? (e.g., suppose a large Nuclear unit that historically constituted the largest
unit in a given BAA gets retired? This could present an unintentional compliance trap for the
PRC-005-3 owner, unless this information is routinely updated and published as part of another
NERC Standard, or by some other mechanism wherein the relay engineer could keep abreast of
such changes in a timely manner). 2. 4.2.6.1 – More clarity is needed on exactly what is meant
by “generating plant substations”, since this collective phrase is not defined in NERC’s most
recent Glossary of Terms, dated 05apr13. BGE example: Wagner Unit #4 Sync Breaker is
physically located at Wagner Power Plant, but because the step-up voltage is 230kV, the output
feeds into Brandon Shores 230kV substation, rather than the local 110kV substation where the
other Wagner machines feed into. In this case, would Brandon Shores be considered the
“generating plant substation” for Wagner Unit #4? 3. 4.2.6.2 – The stated inclusion criteria
“one bus away from generating plants specified in Section 4.2.6.1” introduces further
interpretation difficulty when considering other common generating configurations, such as: 1.
The sync breaker is on the low voltage side of the GSU transformer and the GSU high side leads
constitute a “short” transmission line between the Plant (GO) and Substation (TO) 2. Same as
above but the sync breaker is located on the high side of the GSU and connects to the TO
switchyard by the “short” transmission line. 3. The sync breakers owned by the TO are located
in the substation and connected to the high side of the GSU but operated by the GO, again at
the other end of s short transmission line GO. ( A legacy arrangement that results from the
disintegration of formerly vertically integrated utilities) 4. Sync breaker on the high side of the
GSU at the plant, but there is a “long” transmission line connecting the sync breaker to a TO
substation.
David Jendras
Ameren
No
Ameren concurs with and also incorporates the SERC PCS comment regarding the interval for
Automatic Reclosing exclusion studies by this reference. Ameren specific comments are: (1) We
request that the SDT add a FAQ: “Automatic Reclosing is a control, not a protective function;
why then is Automatic Reclosing maintenance included in the Protection System Maintenance
Program (PSMP)?” Answer: “Yes, Automatic Reclosing is a control function. The standard’s title
‘Protection System and Automatic Reclosing Maintenance’ clearly distinguishes its function
from the Protection System. Automatic Reclosing is included in the PSMP because it is more
concise than creating a parallel and essentially identical ‘Control System Maintenance Program’
for the two Automatic Reclosing component types.” (2) We request that the SDT add a FAQ:
“Our maintenance practice consists of initiating the Automatic Reclosing relay and confirming
the breaker closes properly. This practice verifies the Control circuitry associated with
Automatic Reclosing including the close coil. Do you agree?” Answer: “Yes, since the breaker
does successfully close in your practice. The intent of the Unmonitored Control circuitry
Maintenance Activity is for the entity to functionally prove the Automatic Reclosing control
path is intact through the breaker close coil.” (3) We request that the SDT revise the Countable
Event definition because as written it incorrectly implies that an Automatic Reclosing failure is
a Misoperation. We believe that the Automatic Reclosing exclusion needs to be moved to a
different sentence. (4) We request that the SDT add a FAQ: “Why was a close-in three phase
fault present for twice the normal clearing time chosen for the Automatic Reclosing exclusion?
It exceeds TPL requirements and ignores the breaker closing time in a trip-close-trip sequence,
thus making the exclusion harder to attain.” Answer: “This test was chosen intentionally to err
on the side of conservatism.” (5) We request that the SDT augment the FAQ 2.4.1 to include
“IEEE Device No. 79” in referring to the Automatic Reclosing relay because this helps clarify the
scope.
Yes
PacifiCorp
Ryan Millard
PacifiCorp
Yes
Yes
Chris Mattson
Tacoma Power
Yes
Tacoma Power has the following comments regarding improvements to the standard: 1.
*Regarding 4.2.6.1 and 4.2.6.2, there are some generating plants that may be in a different
Balancing Authority area than the Transmission Owner with which they interconnect. This may
complicate the determination of applicability of Automatic Reclosing under PRC-005-3. 2.
Regarding 4.2.6.2, would it be necessary to maintain Automatic Reclosing components per
PRC-005-3 on BES Elements “facing” an applicable generating plant? For example, assume that
a 5-circuit-mile long line connects Generating Plant A with Substation B. Would Automatic
Reclosing components at Substation B on the connecting line need to be maintained per PRC005-3? It seems unlikely that a failure of the Automatic Reclosing in this scenario would have
adverse reliability impact to the BES. Of course, this assumes that there is not another
generating plant within 10 circuit miles connected to Substation B. 3. Consider a substation
located within 10 circuit miles of two or more generating plants, none of which individually
applies under 4.2.6.1. Furthermore, assume that these generating plants collectively have a
total installed generating plant capacity greater than the capacity of the largest generating unit
within the Balancing Authority area? Would the substation apply to 4.2.6.2? 4. In 4.2.6.2, only
Automatic Reclosing applied on BES Elements is applicable. What if there is a non-BES radial
line connected to the substation? It seems that the reliability impact of improper Automatic
Reclosing on this non-BES Element could be as high as that for improper Automatic Reclosing
on a BES Element connected to the substation.
Yes
Kayleigh Wilkerson
Lincoln Electric System
No
LES is concerned with how components of a reclosing system would be identified if an
automatic line isolation scheme is included within a reclosing scheme. For instance, in some
configurations, if a trip were to occur on a transmission line, one reclose is performed. If the
line immediately trips again (i.e., the fault is not cleared), the line is automatically isolated with
a line switch followed by a second reclose. This is done in order to pick up the load on a
transformer that may be on the same line terminal at the substation. However, in the event
there is a failure of the line switch, the second reclose is cancelled. In consideration that this
would affect reclosing, LES asks that the drafting team provide further clarification as to
whether the components associated with the line switch operation would be included as part
of the PSMP as well. Additionally, if reclosing is supervised by a sync-check function, whether
included in the relay performing the reclosing or else in a separate relay, should that relay, and
the voltage inputs needed to do sync-check, be included in the PSMP also? To ensure a
consistent understanding amongst registered entities, LES recommends the drafting team add
clarifying language to Applicability Section 4.2.6 or else provide further guidance within the
Supplementary Reference and FAQ document.
Yes
Thomas Foltz
American Electric Power
No
It is not clear exactly which sort of automatic reclosing behavior(s) the proposed changes are
attempting to prevent. Accidental reclosing? Failure to reclose? Providing clarity on this
fundamental question will help industry in providing sound comments and feedback regarding
PRC-005-3. Does mentioning “interlock circuits” in the second bullet under Automatic
Reclosing (page 2 of redline) refer narrowly to circuitry inside breaker mechanisms or does it
also include lockout strings associated with lockout relays?
No
We are concerned by the second bullet in the General Considerations section where it states”
Whether each component has last been maintained according to PRC‐005‐2 (or the combined
successor standard PRC‐005‐3), PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, PRC‐017‐0, or a
combination thereof.” This section implies obligations which reference standards outside of
PRC-005-3 and including a standard which is not yet fully approved (PRC-005-02), essentially
serving as Measures outside of the proposed standard. In addition, obligations have no place in
an implementation plan if they are not also specified within the standard itself. This overall
approach sets a bad precedent for the standards development process. AEP does not
recommend basing an implementation date on a standard which has not been fully approved,
as that could prove problematic if in this case PRC-005-2 fails to become fully approved by
FERC but PRC-005-3 *is* approved. Ideally, we recommend that the implementation date be
solely based on PRC-005-3. However, should the drafting team still wish to include PRC-005-2
in the implementation plan, perhaps it could instead state that “Unimplemented Protection
System Component maintenance activities per PRC-005-2 will continue to be implemented in
accordance with the PRC-005-2 implementation plan. In addition, the following Automatic
Reclosing Component maintenance activities will be implemented as part of PRC-005-3…”
Pepco Holdings Inc & Affiliates
David Thorne
Pepco Holdings Inc
No
We agree with the reasoning behind NERC’s System Analysis and Modeling Subcommittee
(SAMS) recommendation to limit the applicability of automatic reclosing to only those
installations that would impact the reliability of the BES. The three criteria (Sections 4.2.6.1,
4.6.2.2, and 4.6.2.3) identified in the PRC-005-3 draft and FAQ document seem reasonable and
appropriate. However, additional clarification is needed to ensure uniform interpretation of
these criteria. Consider the following scenario. Suppose a certain generating plant has 500
MVA of generation interconnected at a 230kV bus, 300 MVA interconnected at a 138kV bus,
and 200 MVA interconnected at a 69kV bus. There are autotransformers connecting the 138kV
bus to both the 230kV and 69kV busses. 1 ) How is total plant capacity to be calculated? Is it
the sum of all generation capacity at the plant (500 + 300 + 200 = 1000 MVA), even though it is
not all interconnected at the same bus, and some of it is connected below 100kV? Or, should
the aggregate generation capacity interconnected on each bus be evaluated separately for
those lines connected to that bus? Depending on the size of the autotransformers which
interconnect the three busses, the transformer thru impedance could be comparable to, or
exceed, the equivalent impedance of 10 circuit miles of line. If this were the case, it would
seem that evaluation of plant capacity should be permitted to be calculated on an individual
bus basis, rather than a total plant basis. Also, can the 200 MVA of generation interconnected
at the 69kV bus be excluded from the total plant capacity, since it is interconnected below
100kV, and therefore not BES generation? Section 4.2.6.1 should be re-worded to provide
clarity and eliminate confusion on how to evaluate this plant capacity calculation. Also, specific
examples illustrating how to apply this criterion would be helpful in the FAQ. 2 ) Section 4.2.6.1
states that it applies to “all BES elements at generating plant substations…”. The transmission
line (including both ends) is considered a BES element. Therefore one might interpret this as
applying to both ends of any BES element that terminates on a generating plant substation. We
believe the intent of 4.2.6.1 is to only apply to the automatic reclosing schemes on the line
terminals located at the generating station and to not apply to the automatic reclosing
schemes on the opposite ends of the lines remote from the generating plant substation.
Automatic reclosing schemes on lines terminating on generating stations usually employ a
leader-follower philosophy, with the remote terminal programmed as the reclose initiate
terminal, and the generating station end of the line reclosing only upon a successful restoration
of the far end. A reclosing mal-function at the far terminal should have no consequences for
the generating plant, provided there is no other electrically short (within 10 circuit miles)
transmission path from the far terminal back to the generating plant. To provide clarity, Section
4.2.6.1 should be re-worded as follows: “Applied on the terminals of BES Elements located at
generating plant substations…”. For consistency, Section 4.2.6.2 should also be re-worded as
follows: “Applied on the terminals of BES Elements located at substations…”. Also, specific
examples and clarifications in the FAQ would also be helpful. 3 ) For consistency, when
determining plant capacity and capacity of the largest generating unit within the Balancing
Authority Area, rated generator nameplate MVA ratings should be used rather than published
seasonal MW values. 4 ) The NERC SAMS review concluded that automatic reclosing malperformance affects BES reliability when “inadvertent reclosing near a generating station
subjects the generation station to severe fault stresses”. The concern appears to be potential
shaft torque damage, or instability, of rotating machines to automatic reclosing malperformance. That being the case, generation sources that are not subject to severe fault
stresses, such as inverter based generation, or static reactive sources (SVC’s, capacitor banks,
etc.) should not be included in the calculation of total plant capacity. However, since
synchronous condensers are subject to the same fault stresses as synchronous generators they
should probably be included in the aggregate plant generation calculation, providing they are
interconnected at 100kV, or above.
Yes
Brad Harris
CenterPoint Energy
No
The SAMS/SPCS study of automatic reclosing identifies 1 circuit-mile impedance as typically
adequate to prevent generating unit instability and that 10 circuit-miles impedance is a
sufficient margin. CenterPoint Energy requests that the SDT reevaluate the technical basis for
selecting 10 circuit-miles as “sufficient margin” and incorporating this distance into the
Applicable Facilities section 4.2.6.2. Since the SAMS/SPCS study states that 1 circuit mile
impedance is adequate, it is possible that 5 circuit-miles or some other distance will provide a
sufficient margin.
Yes
SERC Protection and Controls Subcommittee
David Greene
SERC RRO
No
Under the Facilities Section, the drafting team included Footnote #1 which allows an exclusion
of certain locations that meet the test criteria; however, there is no stated time frame to revalidate the results of stated test. We recommend that the drafting team specifies a revalidation period of 60 months.
Yes
Andrew Z. Pusztai
American Transmission Company
No
The PRC-005 standard is directed at the Transmission Owner (TO), not the Transmission
Planner (TP). The TO may not have the ability to perform the analysis that is required to
identify exclusions and ATC recommends that the SDT address this issue.
MRO NERC Standards Review Forum
Russ Mountjoy
MRO
Yes
The NSRF supports the draft standard PRC-005-3 addressing automatic reclosing as correct and
appropriate.
Yes
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
The maintenance for Automatic Reclosing installed on the lines defined at Section 4.2.1 should
be done at the same time with the maintenance of Protection Systems installed on those lines.
Similarly, the maintenance for Automatic Reclosing used as an integral part of a SPS defined in
Section 4.2.4 should be done at the same time as the maintenance for a SPS. This should be
reflected in this revision of the Standard. The Considerations for Maintenance and Testing of
Autoreclosing Schemes report attached as a supporting document mentions as a credible
failure “a close signal is issued with no delay or less delay than is intended”. This failure should
be classified as either a normal contingency or an extreme contingency. The classification is
important because the TPL standards define different study conditions based on contingency
classifications. How are interconnections to be considered in Applicability Section 4.2.6
Automatic Reclosing? Section 4.2.6.1 states that Automatic Reclosing should be maintained “at
generating plant substations where the total installed capacity is greater than the capacity of
the largest generating unit within the Balancing Authority Area”. However, depending on the
assumptions used for system configurations, there may be other locations where if the double
three phase fault described in Footnote 1 is applied, the total generation loss could be greater
than the largest unit within the Balancing Authority. Also, should the criteria be based on
largest single source loss rather than largest generating unit? Otherwise, there is no
mechanism that triggers review of applicability of this standard. For example, what if the
largest generating unit within the BA Area is removed permanently from service? This is
applicable in the Northeast, where TO and GO functions are performed by different
entities/owners. The BA is the entity that determines the largest single source loss in its area;
they would also be the proper functional entity to identify the generator locations in 4.2.6.1.
The TPL or the BAL standards could then include a trigger mechanism to review applicability of
4.2.6 to GOs and TOs for a change in the largest single source loss criteria/limit. From a
Registration Criteria perspective, the terms “unit” and ”plant” as employed in the Registration
Criteria suggest a two-part Applicability test. The first part is a comparison between the single
“largest generating unit” and a larger multi-unit generating plant located at a single site (i.e.,
the term a “plant” as used in NERC Rules of Procedure, Appendix 5B NERC Statement of
Compliance Registry Criteria). In this first part of the test the sum of the capacity ratings of the
smaller individual units exceeds the single “largest generating unit” within the Balancing
Authority Area. This is compared with a single “largest generating unit.” The second part of the
Applicability test relates to the “generating plant substations.” In this phrase the word
“substations” is plural. This plural wording suggests that the multi-unit generating plant feeds
more than one substation. Suggest the following alternatives to the wording of Section 4.2.6.1:
“Where generating plant substations are interconnected locally at the generating plant site, or
adjacent to the generating plant site, and applied on BES Elements at the generating plant
substations.” Or “Automatic Reclosing is applicable where the total site installed generating
plant capacity is greater than the capacity of the largest generating unit within the Balancing
Authority Area or when 4.2.6.3 applies.” Applicability Section 4.2.6.2 addresses the electrical
and geographical proximity of the “generating plant substations” interconnections by stating
“one bus away” and “less than 10 circuit-miles from the generating plant substation.” For
clarification, suggest revising Section 4.2.6.2 to read “Where generating plant substations are
interconnected at a distance from the generating plant site, applied on BES Elements at
substations located one bus away from generating plant substations when the substation is
less than 10 circuit-miles from the generating plant substation.” What is the technical
justification for the 10 circuit-miles? It may be necessary to confirm the 10 circuit miles with
the Planning Coordinator. It is not clear if a substation “one bus away from generating plants”
that meets the criteria in 4.2.6.2 and includes buses at two voltage levels, separated by a
power transformer, is considered as one bus, or as two buses separated by a power
transformer. If the former applies, reclosing relays on elements at only one of the substation
buses would be included in this standard. If a reclosing relay is found non-functional during
maintenance activity and has to be removed from service for an extended period of time,
which in turn fully removes automatic reclosing functionality, is it still identified as an
Unresolved Maintenance Issue? The final SAMS-SPCS report states that if “No close signal is
issued under conditions that meet the intended design conditions, (…) this failure mode does
not create any additional considerations for inclusion of autoreclosing relays in PRC-005”,
which implies that it would not be identified as an Unresolved Maintenance Issue. Footnote 1
is not explicit as to the reclosing operation referred to. The Requirement appears to address
only three pole, single shot reclosing. There is no reference to single pole reclosing or cases
where multiple shot reclosing may be utilized. A more generalized statement should be
considered: Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if
the equipment owner can demonstrate that, in the event of a close-in permanent fault, the
reclosing utilized does not result in a total loss of generation in the Interconnection exceeding
the largest unit within the Balancing Authority Area where the Automatic Reclosing is applied.
Rationale should be provided to describe the system conditions to be considered for studying
the three phase fault described in Footnote 1. Footnote 1 places the burden on the owner of
the reclosing relays to demonstrate which reclosing relays can be excluded by making the
determinations outlined in the footnote. This should be the role of the Reliability Coordinator
or Planning Coordinator and not the equipment owner. Consequently, we believe that the
applicability of this standard should be expanded to RCs and/or PCs in order to properly
conduct the sort of studies asked for in the standard. Section 4.2.6.3 is not specific enough with
regard to reclosing used in an SPS. The use of the word “integral part of an SPS” is subject to
interpretation and may require details of the SPS that will not be readily available to the owner
of the reclosing relays. There should be a process in place to update the list of the Automatic
Reclosing excluded from being maintained. The standard must consider that neighboring
entities may be involved in the lines being tested.
Yes
Hydro One Networks Inc.
Sasa Maljukan
Hydro One Networks Inc.
No
We do not agree with Footnote 1 in the standard which places the onus on the equipment
owner of the reclosing relays to demonstrate which reclosing relays can be excluded by making
the determinations outlined in the footnote. This is clearly the role of the Reliability
Coordinator or Planning Coordinator and not the equipment owner. Consequently, we believe
that the applicability of this standard should be expanded to RCs and/or PCs in order to
properly conduct the sort of studies asked for in the standard. Also, the standard assumes
that all relays are in scope and entities have to systematically exclude relays based on the
footnote. We don’t agree with this approach since it is onerous and leaves room for
interpretations. We suggest that standard is changes so that the onus is placed on the RC or PC
to identify such relays. Section 4.2.6.3 is not specific enough in terms of in-scope reclosing
used in an SPS. Use of the word “integral part of an SPS” is subject to interpretation and may
require details of the SPS not readily available to the owner of the reclosing relays. We
propose that the maintenance for Automatic Reclosing installed on the lines defined at Section
4.2.1 should be done at the same time with the maintenance of Protection Systems installed
on those lines. If the owner of the two relays is not the same, we recommend that the standard
requires coordination between two entities. Similarly, the maintenance for Automatic
Reclosing used as an integral part of a SPS defined in Section 4.2.4 should be done at the same
time with the maintenance for SPS. The revision of the standard should only reflect these
changes. Please see the rational below: The report attached as a supporting document
mentions as a credible failure “a close signal is issued with no delay or less delay than is
intended”. This failure should be classified as either a normal contingency or an extreme
contingency. The classification is important because the TPL standards define different study
conditions based on contingency classification. Sections 4.2.6.1 states that Automatic Reclosing
should be maintained “at generating plants substations where the total installed capacity is
greater than the capacity of the largest generating unit within the Balancing Authority”.
However, depending on the assumptions (how the system is stressed, extreme weather, etc.)
and specific configurations, there may be other locations, where if the double three phase fault
described in the Footnote 1 is applied, the total generation loss could be greater than the
largest unit within the Balancing Authorities. The standard lacks a common methodology for
performing the double three phase fault described in the Footnote 1: The standard does not
specify the conditions (extreme weather base case, extreme contingencies base case, how the
generators are dispatched, etc.) or what would be the time delay between the first and second
fault. All these conditions may affect the total generation loss. The 10 circuit-miles criteria
should be confirmed with the Planning Coordinators. Depending on the location of the line
being tested, different neighboring entities may be involved. There should be a process in
place to update the list of the Automatic Reclosing excluded from being maintained.
Yes
Bill Fowler
City of Tallahassee
Yes
Anthony Jablonski
ReliabilityFirst
No
No, the reclosing relays in the Applicability section were overly restricted. Improper operation
of reclosing relays can exacerbate fault conditions and severely damage equipment that affects
the long term reliability of the Bulk Power System. The Applicability section limits the facilities
concerning automatic reclosing to those integral to an SPS or substations (and those one bus
away) where the total installed generating plant capacity is greater than the capacity of the
largest generating unit within the Balancing Authority Area. This bar is so high that substations
with units as high as 1200 MVA may not be covered by this revised standard. The capacity limit
should either be removed or reduced to no more than half the largest generating unit within a
BA. Also, the definition of Automatic Reclosing should include supervisory elements like
synchronism check or dead-line check as these can be integral parts of the reclosing scheme.
No
No, the implementation plan has an excessively long phased in approach that stretches out to
13 years after regulatory approval or 14 years after NERC Board of Trustees adoption
Southern Company - Southern Company Services, Inc.; Alabama Power Company;Georgia
Power Company; Mississippi Power Company; Gulf Power Company; Southern Company
Generation; Southern Company Generation and Energy Marketing
Marcus Pelt
Southern Company Operations Compliance
Yes
Under the Facilities Section, the drafting team included Footnote #1 which allows an exclusion
of certain locations that meet the test criteria; however, there is no stated time frame to revalidate the results of stated test. We recommend that the drafting team specifies a revalidation period.
Yes
Cole Brodine
Nebraska Public Power District
No
*4.2.6.1 – Is the largest generator included or excluded? Based on the definition, the largest
generator is not larger than the largest generator, so it would not be included. *Confirm other
input to Automatic reclosing Relays are NOT included (including but not limited to…): Synch
check relays. Voltage sensing devices Please explain or clarify better what the SPS includes,
spefically what does “integral part” mean? Please explain what a minimum trip-close-trip time
delay is and how this exclusion would work. Please clarify which circuitry is applicable. An
example would be A/B contacts, are these included or not?
No
To implement, it would cause us to have to verify that the reclose actually works as part of the
functional trip check. Otherwise, we have the breakers and relays already classified as NERC.
PPL Corporation NERC Registered Affiliates
Nicholas A. Poluch
PPL Generation, LLC on behalf of its Supply NERC Registered Entities
No
1) There are currently two NERC approved projects filed at FERC (PRC-005-1.1b and PRC-0052). NERC should consider waiting to proceed with this project until the current projects are
ruled on and FERC provides further direction. 2) For 4.2.6, for reclosing capability, it is unclear
what functionality is to be tested. Please define. 3) For PRC-005-3 section 4.2.6.2, please
provide the technical basis for this application of the Standard. Specifically, this application
states for Automatic Reclosing: “Applied on BES Elements at substations one bus away from
generating plants specified in section 4.2.6.1 when the substation is less than 10 circuit miles
from the generating plant substation.” Please provide the technical basis/reasoning for the 10mile criteria. At a recent North American Transmission Forum Workshop on Protection System
Maintenance Program it was implied that the 10 mile rule is for cases where a generator has a
short connection to another company’s substation. Please clarify if this is the case. 4) For PRC005-3 section R1, consider adding the following language that is used for PRC-005-1.1b “each
Generator Owner that owns a generation or generator interconnection Facility Protection
System...” This is NERC-approved language that has been through the standards development
process and has technical justification through Project 2010-07. 5) Please provide the technical
basis for R1.1 which requires battery testing for DC Supply Component Type Protection
Systems to be time based. 6) Table 1-2 of PRC-005-3 requires functional testing of nonmonitored communication systems on a 4 month cycle. Please specify NERC’s criteria for the
functional testing (what attributes to be tested). Additionally, specifically define monitoring
criteria and data intervals for continuous monitoring of communications systems (to see if
check back (fail/no fail) monitoring is adequate).
Yes
Oliver Burke
Entergy Services, Inc.
Yes
Entergy agrees with the inclusion of the reclosing relay maintenance requirement except for
how the terminology is addressed. Entergy suggests not adding of the term Automatic
Reclosing; instead add reclosing relay and the associated circuitry description under Protection
System definition.
Yes
Entergy agrees with the addition of table 4 except for the terminology Automatic Reclosing.
ISO RTO Council Standards Review Committee
Greg Campoli
NYISO
No
The IRC members compliment the SDT in using the recommendations provided in the
SAMS/SPCS Order 758 Autoreclosing Report for the applicability of this standard directive to
specific reclosing relays. By using these recommendations, Transmission Owners are provided
guidance and reduced burden that should satisfy the Commission conclusion in the Order that
“specific requirements fo selection criteria should be used to identify reclosing relays that
affect the reliability of the Bulk-Power System.” The IRC members are not directly impacted by
the PRC-005 requirements from a compliance standpoint because we are generally not
Transmission Owners. We are raising these questions to highlight the lack of communications
between the stakeholder industry experts and the regulator directing technical requirements
on the industry . As everyone in the industry knows, seven years’ experience with the ERO has
caused significant burdens on meeting compliance requirements with numerous requirements
being in effect and entities having to significantly increase resources in compliance and not
always justifying whether such expenses are a benefit to the end consumer. NERC must
develop processes and form relationships with the regulators who have these specific technical
concerns to bring their concerns and issues to the industry experts in a more direct and
efficient manner to avoid delays in standards development and approval and expending more
resources in the regulatory process rather through a technical process. We question whether
the approach the SDT has taken to address the FERC Directive in Order 758 addresses the core
reliability concern that the Order seems to raise. First, the Order states that reclosing relays are
not explicitly identified as part of the “Protection System” and if it plays a part in the
“Protection System” to “achieve or meet system performance requirements” or “can
exacerbate fault conditions when not properly maintained and coordinated” then there could
be a gap in the maintenance and testing of the relays. Second the Order recognizes that certain
parties in comments to the NOPR believe reclosing relays are used not for reliability reasons
but for business purposes in restoration post-contingency. Further commenters stated that
specific call outs for reclosing relays in PRC-005 are not necessary because reclosing relays are
already integral to an entity’s relay maintenance program. Nevertheless, FERC has directed
NERC to add reclosing relays to the standard There is no further technical justification for
adding reclosing relays to the standards. The referenced language from the Order can be
challenged by a protection system designer in that a reclosing relay may not be integral to
“achieve or meet system performance requirements” nor “can exacerbate fault conditions”
because they may have been designed to provide onlyrestoration of service for customer
satisfaction and be in a part of the system that cannot exacerbate a fault condition (e.g. tap
configuration). Does a registered entity subject to this requirement have the ability to
demonstrate a particular reclosing relay does not meet the apparent reliability concern
specified in the Order and exclude those reclosing relays from the compliance program? An all
inclusive approach to apply the PRC-005 requirements for all reclosing relays may have little to
no reliability benefit to the grid. In addition, we offer the following comments for the SDT’s
consideration to achieve consistency in the terms used and the precise devices that the revised
standard should apply: a. Definition of PSMP: the term “Automatic Reclosing” should not be
capitalized since it is indicated that the term is defined for use only within PRC-005-3, and
should remain with the standard upon approval rather than being moved to the Glossary of
Terms. With this term not to be balloted and included in the Glossary, it should be in lower
case. b. Order 758 directed NERC to include “reclosing relays” that can affect the reliable
operation of the Bulk-Power System. Automatic reclosing is an act or intent, not a device. It is
the latter that needs to be maintained and tested for continued functionality, not the former.
Therefore, we suggest that the term “Automatic Reclosing” be replaced with “reclosing
devices” or “reclosing relays” in the revised PSMP definition, in Sections A.1, A.3 and A.4.2.6,
and throughout the standard where “automatic reclosing” is addressed/referenced. c. We
interpret the FERC directive to require not just the automatic reclosing devices/relays be
included in PRC-005, but also the relays/devices that may be used for manual reclosing. In
other words, both automatic and manual reclosing devices/relays need to be included in the
standard. To enable this applicability, we suggest not removing the word “automatic” where it
appears.
Yes
We agree with the proposed implementation plan, but suggest that the term “Automatic
Reclosing” with “reclosing devices” or “reclosing relays” be applied throughout the
Implementation Plan document (see out comments under Q1, above).
Duke Energy
Colby Bellville
Duke Energy
No
We believe the modifications to the PRC-005-2 Applicability section 4.2.6.1 should recognize
that the reliability issue is inadvertent reclosing, and therefore applicability on BES Elements at
generating plant substations should be limited to the timing and sync check functions of
reclosing. There is no need to include all DC circuitry, etc. because if a problem existed aside
from timing and sync check, it would just prevent reclosing. Also, rather than being focused
only on plant capacity, there should be some recognition that plant location on the BES is also a
consideration. Duke Energy believes the Applicability section 4.2.6.2 should be based on a
technical assessment as illustrated in the SAMS/SPCS paper. This type of assessment should be
based on a simulation of a close-in-three-phase fault for twice the normal clearing time. This
simulation would capture a minimum trip-close time delay.
Yes
Kevin Luke
Georgia Transmission Organization
Agree
Michael Falvo
Independent Electricity System Operator
No
Comments: We only agree with the scope presented in the SAR. We do not agree with the
proposed changes, as stated below. We suggest that the maintenance for Automatic Reclosing
installed on the lines defined at Section 4.2.1 could be done at the same time with the
maintenance of Protection Systems installed on those lines. Similarly, the maintenance for
Automatic Reclosing used as an integral part of a SPS defined in Section 4.2.4 could be done at
the same time with the maintenance for SPS. Please see the rational below. The report
attached as a supporting document mentions as a credible failure “a close signal is issued with
no delay or less delay than is intended”. This failure should be classified as either a normal
contingency or an extreme contingency, to be consistent with the TPL standards contingency
classification. Section 4.2.6.1 states that Automatic Reclosing should be maintained “at
generating plants substations where the total installed capacity is greater than the capacity of
the largest generating unit within the Balancing Authority”. However, depending on the
assumptions (how the system is stressed, extreme weather, etc.) and specific configurations,
there may be other locations, where if the sequential three phase fault described in the
Footnote 1 is applied, the total generation loss could be greater than the largest unit within the
Balancing Authorities. The standard lacks a common methodology for testing sequential three
phase faults described in the Footnote 1: o The standard does not specify the conditions
(extreme weather base case, extreme contingencies base case, how the generators are
dispatched, etc.) or what would be the time delay between the first and second fault. All these
conditions may affect the total generation loss. o The 10 circuit-miles criteria should be
confirmed with the Planning Coordinators. o Depending on the location of the line being
tested, different neighboring entities may be involved. o There should be a process in place to
update the list of the Automatic Reclosing excluded from being maintained.
Yes
FirstEnergy
Larry Raczkowski
FirstEnergy Corp
No
1. FE supports the technical aspects and requirements of the standard. 2. FE is questioning the
accuracy of the red-lining in this document. Many of the definitions were reflected as “new”
when in fact only minor changes were made. 3. FE also questions why the drafting team is
proposing deletions in the Revision History of the standard. Complete and accurate revision
history is information that needs to be retained for future reference.
Yes
FE agrees with the proposed Implementation Plan for V3.
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
No
FMPA is generally supportive of the changes to the standard to accommodate Reclosing Relays
as directed by FERC. We have one comment: The SDT should recognize that there are a number
of small BAs and that the Applicability 4.2.6.1 would be better stated as the largest generator
within the Reliability Coordinator area as opposed to the largest generator in the Balancing
Authority area (e.g., for some BAs, the largest generator in their area is less than 10 MW and
not even registered). If left unchanged, FMPA would recommend a Negative vote.
Yes
Jonathan Meyer
Idaho Power Company
Yes
Yes
ACES Standards Collaborators
Jason Marshall
ACES
No
(1) While we believe the standard should not be modified until FERC rules on version 2 of PRC005, we appreciate that the drafting team adopted the recommendations of the Planning
Committee in limiting the applicable reclosing relays to only those that may impact reliability.
Limiting applicability to only those auto-reclosing relays that are close to large generating
stations or that are applied as part of an SPS appears to fully meet the intent of the FERC
directive. This limited applicability will help avoid the negative reliability impacts that would
occur as a result of expanding applicability. If all auto-reclosing relays were included, the
standard would detract resources away from reliability needs to unnecessary documentation.
(2) We have a concern with the “Auto Reclosing” definition being proposed in this draft
standard. Some parts of the definition may require further clarification and may be vague.
What does “such as anti-pump and ‘various’ interlock circuits” mean? Will auditors and
industry subject matter experts understand them in the same way? “Various” is not a clear
adjective to describe interlock circuits. We recommend revising the entire definition to clearly
state the scope of the devices (possibly even the IEEE numbers). (3) There are concerns with
the supplementary reference document because it assumes that PRC-005-2 will be approved
by the Commission. This assumption is presumptuous and should not reflect any Commission
rulings that have yet to occur. We recommend stating the current status of the PRC-005-2
project, which was filed with FERC in February 2013 and is pending the Commission’s approval.
Statements such as “PRC-005-2 ‘replaced’ PRC-011” should be modified to “PRC-005-2 will
replace PRC-011 upon approval from FERC,” or something similar. (4) We suggest additional
clarification may be needed for section 4.2.6.1 regarding applicability of auto-reclosing relays.
This section states that the standard will apply to auto-reclosing relays implemented at the
generating plant substation where installed generating plant capacity is greater than the
largest generating unit in the BA. We presume this was selected because the largest generating
unit is often the most severe single contingency and establishes the amount of contingency
reserves that must be carried. If our assumption is correct, we would suggest that the
applicability may need to be based on the largest resource in a Reserve Sharing Group (RSG) or
BA. There is at least one large BA in the Eastern Interconnection where the largest resource is
actually the loss of a 500-kV line that triggers a generation runback scheme. If a BA participates
in an RSG, the BA would have access to contingency reserves that would be carried by the
group and, thus, the only time a call for contingency reserves would exceed the amount carried
would be when the generation loss is greater than the largest resource in the RSG.
No
(1) The SDT needs to clarify the implementation plan. The document is confusing because it
focuses on the PRC-005-2 standard, which is not yet FERC-approved. As a result, this
implementation plan is a moving target. Why not wait until PRC-005-2 gets approved before
initiating another project for the same standard? This would reduce some of the timing issues
and confusion. (2) Why is the drafting team revising a standard that has not been approved by
the Commission yet? The second version was only filed in February 2013, and the timing of this
project is premature. It is quite possible that the Commission could remand or direct revisions
to parts of the standard and issue other directives associated with the version 2, which would
then need to be addressed. This project is untimely and should be postponed until there is a
final order from FERC. At that point, there may be justification to continue with this project,
expand the scope of the SAR to address any new directives that may be included in a final
order of PRC-005-2, or to determine that a guidance document is an appropriate way to satisfy
the FERC orders. (3) Again, the drafting team needs to consider other methods of answering
FERC directives. Not every directive needs to be addressed by developing or revising a
standard. Adding reclosing relays to PRC-005 only complicates the most-violated non-CIP
standard. There is enough concern about this standard already and the drafting team should
consider alternative means to address the reclosing relay issue besides a standard revision. (4)
This project contains similar timing issues as CIP version 4 and CIP version 5 because it is being
developed prior to FERC issuing a final order on the previous version of the standard. The
timing is problematic; registered entities will be forced to constantly be focusing on the next
standard. The implementation plan should provide additional time, similar to PRC-005-2’s two
intervals, to allow registered entities enough time to adjust their PSMT programs for Protection
Systems, and then have additional time to adjust their PSMT plan and implement autoreclosing relays. (5) Thank you for the opportunity to comment.
Scott Langston
City of Tallahassee
Yes
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program
Yes
Yes
Consideration of Comments
Project 2007-17.2 Protection System Maintenance and
Testing – Phase 2 (Reclosing Relays)
The Project 2007-17.2 Drafting Team thanks all commenters who submitted comments on the
Standard Authorization Request (SAR) for Protection System Maintenance and Testing (Reclosing
Relays). The SAR was posted for a 30-day formal comment period from April 5, 2013 through May 6,
2013. Stakeholders were asked to provide feedback on the SAR and associated documents through a
special electronic comment form. There were 24 sets of comments, including comments from
approximately 93 different people from approximately 64 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration of all Comments Received
SAR
The SAR was previously posted for information only along with the third draft of PRC-005-2 in May,
2012. The Standards Process Manual supports posting of a SAR for a comment period at the same time
that a draft of the resulting standard is posted for a formal comment period. “For SARs that are limited
to addressing regulatory directives, or revisions to Reliability Standards that have had some vetting in
the industry, authorize posting the SAR for a 30-day informal comment period with no requirement to
provide a formal response to the comments received.”
Commenters agreed that the scope of this SAR addresses the regulatory directive associated with
Order 758 while a few commenters suggested that NERC pursue “equally efficient and effective”
methods for achieving the reliability intent of the FERC directive regarding the maintenance of
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
reclosing relays. The drafting team noted that “equally efficient and effective” alternatives were
proposed to FERC in the NOPR preceding Order 758, and they were rejected.
No regional variances were identified as being necessary because of this project.
Two commenters noted they may need to modify or establish business practices.
The drafting team removed the parenthetical and revised a sentence of the SAR’s “Need” statement
because the SAMS and SPCS could not identify an application in which autoreclosing is used in
coordination with a protection system to meet the system performance requirements in a NERC
Reliability Standard or in establishing an IROL. The sentence was formerly read: “Modifying the
standard in this fashion will impact Bulk Electric System (BES) reliability by assuring that the reclosing
relays (installed to meet performance goals of approved NERC Standards) are properly maintained so
that they may be expected to perform properly.” It now reads:“Modifying the standard in this fashion
will assure that those reclosing relays that can affect the reliability of the Bulk Electric System are
properly maintained.”
Index to Questions, Comments, and Responses
1.
Do you agree that the scope of this SAR addresses the regulatory directive associated with FERC
Order No. 758? If not, please explain. .............................................................................. 9
2.
Are you aware of any regional variances that will be needed as a result of this project? If yes,
please identify the regional variance. .............................................................................15
3.
Are you aware of any business practice that will be needed or that will need to be modified as a
result of this project? If yes, please identify the business practice. .......................................18
Consideration of Comments: Project 2007-17.2
2
4.
If you have any other comments on this SAR that you haven’t already mentioned, please provide
them here: ................................................................................................................21
Consideration of Comments: Project 2007-17.2
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Louis Slade
Dominion
Additional Organization
Region
NERC Compliance Policy
NA - Not Applicable 1, 3, 5, 6
2. Chip Humphrey
Fossil & Hydro
NPCC
5
3. Sean Iseminger
Fossil & Hydro
RFC
5
4. Jeff Bailey
Nuclear
NA - Not Applicable 5
5. Mike Garton
NERC Compliance Policy
1, 3, 5, 6
6. Michael Crowley
Electric Transmission Compliance SERC
1, 3
7. Randi Heise
NERC Compliance Policy
1, 3, 5, 6
8. Matt Woodzell
Fossil & Hydro
2.
Group
Colby Bellville
Duke Energy
3
4
5
6
X
X
X
X
X
X
X
X
Segment Selection
1. Connie Lowe
SERC
2
5
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
3.
Group
Larry Raczkowski
FirstEnergy
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. William Smith
FurstEnergy Corp
RFC
1
2. Cindy Stewart
FirstEnergy Corp
RFC
3
3. Doug Hohlbaugh
Ohio Edison
RFC
4
4. Ken Dresner
FirstEnergy Solutions
RFC
5
5. Kevin Querry
FirstEnergy Solutions
RFC
6
4.
Group
David Thorne
Pepco Holdings Inc & Affiliates
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
Delmarva Power & Light Co RFC
1, 3
2. Carl Kinsley
Delmarva Power & Light Co RFC
1, 3
5.
Group
Robert Rhodes
SPP Standards Review Group
X
Additional Member Additional Organization Region Segment Selection
1. Bud Averill
Grand River Dam Authority SPP
1, 3, 5
2. Timothy Bobb
Westar Energy
SPP
1, 3, 5, 6
3. Afshin Jalilzadeh
Westar Energy
SPP
1, 3, 5, 6
4. Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
5. Bo Jones
Westar Energy
SPP
1, 3, 5, 6
6. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
7. Russ Matzke
Westar Energy
SPP
1, 3, 5, 6
6.
Group
Brandy Spraker
Tennessee Valley Authority
X
X
Additional Member Additional Organization Region Segment Selection
1. Rusty Hardison
SERC
1
2. Ryland Revelle
SERC
1
3. Karen Ryland
SERC
1
Consideration of Comments: Project 2007-17.2
5
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Group
Frank Gaffney
Florida Municipal Power Agency
X
2
3
X
4
X
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
3
8.
Group
FRCC
Jason Marshall
Additional Member
ACES Standards Collaborators
Additional Organization
Region Segment Selection
1. Shari Heino
Brazos Electric Power Cooperative
ERCOT 1, 5
2. Tom Alban
Buckeye Power
RFC
3. Kevin Lyons
Central Iowa Power Cooperative
MRO
4. Megan Wagner
Sunflower Electric Power Corporation SPP
5. John Shaver
Arizona Electric Power Cooperative
6. John Shaver
Southwest Transmission Cooperative WECC 1
7. Scott Brame
NCEMC
9.
Group
3, 4
1
WECC 4, 5
SERC
Guy Zito
Additional Member
X
1, 3, 4, 5
Northeast Power Coordinating Council
Additional Organization
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC
2
3.
Greg Campoli
New York Independent System Operator
NPCC
2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
5.
Chris de Graffenried Consolidated Edison Co. opf New York, Inc. NPCC
1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC
5
8.
Kathleen Goodman
ISO - New England
NPCC
2
9.
Michael Jones
National Grid
NPCC
1
10. David Kiguel
Hydro One Networks Inc.
NPCC
1
11. Christina Koncz
PSEG Power LLC
NPCC
5
12. Randy MacDonald
New Brunswick Power Transmission
NPCC
9
Consideration of Comments: Project 2007-17.2
X
Region Segment Selection
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13. Bruce Metruck
NPCC
6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC
5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
16. Robert Pellegrini
The United Illuminating Company
NPCC
1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC
1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC
5
19. Brian Robinson
Utility Services
NPCC
8
20. Brian Shanahan
National Grid
NPCC
21. Wayne Sipperly
New York Power Authority
NPCC
5
22. Donald Weaver
New Brunswick System Operator
NPCC
2
23. Ben Wu
Orange and Rockland Utilities
NPCC
1
24. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
10.
Jamison Dye
Group
Additional Member
New York Power Authority
Additional Organization
Bonneville Power Administration
3
4
5
SPC Technical Svcs
WECC 1
2. Jason Burt
PSC Technical Svcs
WECC 1
3. Brenda Vasbinder
Work Planning and Evaluation WECC 1
X
X
X
X
X
X
X
X
X
X
X
X
X
Individual
Ryan Millard
Individual
Marcus Pelt
PacifiCorp
Southern Company: Southern Company
Services, Inc; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy Marketing
13.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
14.
Individual
John Bee
Exelon and its Affiliates
X
X
X
15.
Individual
Bill Fowler
City of Tallahassee
X
X
X
12.
6
Region Segment Selection
1. Heather Laslo
11.
2
16.
Individual
Chris Mattson
Tacoma Power
X
17.
Individual
Thomas Foltz
American Electric Power
X
18.
Individual
Brad Harris
CenterPoint Energy
X
Consideration of Comments: Project 2007-17.2
X
X
X
X
X
7
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
19.
Kenn Backholm
Public Utility District No.1 of Snohomish
County
X
Individual
Individual
Andrew Z. Pusztai
American Transmission Company
X
Individual
22. Individual
Anthony Jablonski
Kevin Luke
ReliabilityFirst
Georgia Transmission Corporation
23.
Individual
Jonathan Meyer
Idaho Power Company
24.
Individual
Scott Langston
City of Tallahassee
20.
21.
Consideration of Comments: Project 2007-17.2
2
3
X
4
X
5
X
6
X
7
8
9
10
X
X
X
X
X
8
1. Do you agree that the scope of this SAR addresses the regulatory directive associated with FERC Order No. 758? If not, please
explain.
Summary Consideration:
Commenters agreed that the scope of this SAR addresses the regulatory directive associated with Order 758. No changes made to the
SAR as a result of comments from Question 1.
Some comments pertained to the standard rather than the SAR; however, the drafting team responded to all individual comments.
Several commenters were concerned about initiating the project to establish PRC-005-3 before PRC-005-2 is FERC approved. The
drafting team explained that they are acting in accordance with the schedule provide to FERC in an informational filing submitted by
NERC, in response to FERC Order 758 which stated: “By July 30, 2012, NERC should submit to the Commission either the completed
project which addresses the remaining issues consistent with this order, or an informational filing that provides a schedule for how
NERC will address such issues in the Project 2007-17 reinitiated efforts.” In the Order, FERC accepted NERC’s commitment to address
the maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power System within the standards
development process. Phase 2 (Reclosing Relays) of Project 2007-17 Protection System Maintenance and Testing was initiated to
develop PRC-005-3 and satisfy NERC’s commitment to the FERC.
Several commenters questioned the scope of reclosing relays that might be included in the standard; the drafting team explained
that the SAR provides the boundaries (scope) for the proposed standard action, establishing the general framework for the project.
Several commenters proposed that NERC pursue “equally efficient and effective” methods for achieving the reliability intent of the
FERC directive regarding the maintenance of reclosing relays. The drafting team noted that “equally efficient and effective”
alternatives were proposed to FERC in the NOPR preceding Order 758, and they were rejected.
Several commenters objected to the provision within the SAR that optionally permitted changes to the definition of “Protection
System”. The drafting team explained that this represented one option for the drafting team to consider, and noted that the drafting
team decided not to pursue that option.
Organization
Yes or No
American Electric Power
No
Consideration of Comments: Project 2007-17.2
Question 1 Comment
1. AEP supports the efforts of the drafting team, but is concerned by pursuing a
version 3 of this standard before the second version has been approved by
9
Organization
Yes or No
Question 1 Comment
FERC. There is significant content within version 3 that was new to version 2, so
proper implementation of version 3 would rely on the eventual approval of
version 2 in its entirety. The content of version 3 has apparently been drafted
with this in mind, however, it over-complicates the implementation plan of
version 3 by basing it in-part on the previous and not-yet-approved version, and
leaving it vulnerable in the event version 2 does not pass.
2. In addition, it is not clear exactly which sort of automatic reclosing behavior(s)
the proposed changes are attempting to prevent. Accidental reclosing? Failure
to reclose? Providing clarity on this fundamental question will help industry in
providing sound comments and feedback regarding PRC-005-3.
Response: Thank you for your comments.
1. The drafting team thanks you for your support. The drafting team is acting in accordance with the schedule NERC provided
to FERC, which outlines the timeframes by which NERC will respond, through the standards drafting process, to the
directives of FERC Order 758. Specifically regarding reclose relays (Footnote 37), FERC directed NERC to: “By July 30, 2012,
NERC should submit to the Commission either the completed project which addresses the remaining issues consistent with
this order, or an informational filing that provides a schedule for how NERC will address such issues in the Project 2007-17
reinitiated efforts.”
2. The SAR is general, in that it specifies that requirements for maintenance and testing of reclosing relays be established,
and that “The Applicability section of the Standard must be modified to describe explicitly those devices that entities are
to maintain in accordance with the revised standard.” Further, the SAR notes that the drafting team use the report
prepared by the NERC SPCS and SAMS as an aid in preparing PRC-005-3; this report includes a discussion regarding the
automatic reclosing behavior(s) to be addressed, as well as recommendations regarding the specific applicability.
ReliabilityFirst
No
No, the scope of the SAR only lists three bullet items. It should as a minimum include a
lead in sentence similar to the following: PRC-005-2 has been revised to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the
Bulk Power System. The bullet items do not include the changes made to the
Definitions of Terms, Requirements or Compliance sections.
Consideration of Comments: Project 2007-17.2
10
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. The discussion that you suggest is included in the “Detailed Description” portion of the
SAR.
Dominion
No
The SAR goes beyond the directive in that it appears to indicate that all reclosing relays
must operate properly in order to maintain BES reliability. The fact is that, in a majority
of applications, these relays exist primarily to decrease outage times. The SAR should
be limited to only those reclosing relays whose failure to operate correctly could
adversely impact reliable operation of the BES. Dominion therefore recommends
revising the sentence that reads “The Applicability section of the Standard must be
modified to describe explicitly those devices that entities are to maintain in accordance
with the revised standard.” To read “The Applicability section of the Standard must be
modified to describe explicitly those reclosing relays that entities are to maintain in
accordance with the revised standard.”
Response: Thank you for your comments.
The SAR drafting team agrees that many reclosing relays are installed to facilitate automated restoration, and not to specifically
maintain BES reliability. The SAR therefore states: “The Standard Drafting Team shall modify NERC Standard PRC-005-2 to
explicitly address the maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk Electric
System.” [Emphasis added] When drafting the SAR, consideration was given to concerns that automatic reclosing maintenance
may extend to more than simply the reclosing relays themselves.
ACES Standards Collaborators
Yes
Consideration of Comments: Project 2007-17.2
1. While we agree the SAR addresses the regulatory directive, we question the
value of modifying this standard further when the newest version has yet to be
approved. If FERC issues significant directives, the directives could ultimately
impact the direction that drafting team should take with modifying the
standard to include reclosing relays. Furthermore, because PRC-005 is
historically one of the most violated standards primarily because of the zerodefect approach to compliance, we question the value of adding another relay
type to the list of relays subject to zero-defect compliance. We are concerned
there will be another step function in potential violations that do not ultimately
11
Organization
Yes or No
Question 1 Comment
support reliability but detract from reliability because they are focused on
documentation.
2. We believe that there are other equally-effective options to address the FERC
directives, such as issuing an industry guidance document. If the standard
ultimately needs to be modified, a guidance document could allow the drafting
team to wait until FERC rules on the PRC-005 to determine if there will be any
impacts on adding reclosing relays to the standard.
Response: Thank you for your comments.
1. The drafting team thanks you for your support. The drafting team is acting in accordance with the schedule NERC provided
to FERC, which outlines the timeframes by which NERC will respond, through the standards drafting process, to the
directives of FERC Order 758. Specifically regarding reclose relays (Footnote 37), FERC directed NERC to: “By July 30, 2012,
NERC should submit to the Commission either the completed project which addresses the remaining issues consistent with
this order, or an informational filing that provides a schedule for how NERC will address such issues in the Project 2007-17
reinitiated efforts.”
2. NERC, as well as other entities, provided comments in response to FERC NOPR discussions regarding requirements related
to maintenance of automatic reclosing, essentially proposing equally effective options. FERC, in response, directed that
NERC specifically include requirements related to maintenance of automatic reclosing within PRC-005.
Duke Energy
Yes
However we are concerned that the SAR includes possible revision of the definition of
Protection System. We don’t believe attempting to revise that definition is necessary
or advisable.
Response: Thank you for your comments.
The SAR does provide the drafting team the option to revise the definition of Protection System. The drafting team chose not to
modify the definition.
FirstEnergy
Yes
Pepco Holdings Inc & Affiliates
Yes
Consideration of Comments: Project 2007-17.2
12
Organization
Yes or No
SPP Standards Review Group
Yes
Florida Municipal Power
Agency
Yes
Northeast Power Coordinating
Council
Yes
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Southern Company: Southern
Company Services, Inc;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing
Yes
Manitoba Hydro
Yes
Exelon and its Affiliates
Yes
City of Tallahassee
Yes
Tacoma Power
Yes
Consideration of Comments: Project 2007-17.2
Question 1 Comment
13
Organization
Yes or No
Public Utility District No.1 of
Snohomish County
Yes
American Transmission
Company
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
Consideration of Comments: Project 2007-17.2
Question 1 Comment
14
2. Are you aware of any regional variances that will be needed as a result of this project? If yes, please identify the regional
variance.
Summary Consideration: Commenters did not identify any regional variances that would be needed.
Organization
Yes or No
American Electric Power
No
Dominion
No
Duke Energy
No
FirstEnergy
No
Pepco Holdings Inc &
Affiliates
No
SPP Standards Review Group
No
Florida Municipal Power
Agency
No
ACES Standards Collaborators
No
Bonneville Power
Administration
No
Question 2 Comment
AEP is not aware of any regional variances that would be needed as a result of this
project.
Organization
Yes or No
PacifiCorp
No
Southern Company: Southern
Company Services, Inc;
Alabama Power Company;
Georgia Power Company;
Gulf Power Company;
Mississippi Power Company;
Southern Company
Generation; Southern
Company Generation and
Energy Marketing
No
Manitoba Hydro
No
Exelon and its Affiliates
No
City of Tallahassee
No
Tacoma Power
No
Public Utility District No.1 of
Snohomish County
No
American Transmission
Company
No
ReliabilityFirst
No
Idaho Power Company
No
Consideration of Comments: Project 2007-17.2
Question 2 Comment
16
Organization
Yes or No
City of Tallahassee
Question 2 Comment
No
Consideration of Comments: Project 2007-17.2
17
3. Are you aware of any business practice that will be needed or that will need to be modified as a result of this project? If yes,
please identify the business practice.
Summary Consideration: Two commenters noted they may need to modify or establish their business practices. No changes made to
the SAR.
Organization
Yes or No
Dominion
No
Duke Energy
No
FirstEnergy
No
Pepco Holdings Inc & Affiliates
No
SPP Standards Review Group
No
ACES Standards Collaborators
No
Bonneville Power
Administration
No
PacifiCorp
No
Southern Company: Southern
Company Services, Inc;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
No
Consideration of Comments: Project 2007-17.2
Question 3 Comment
18
Organization
Yes or No
Question 3 Comment
Southern Company
Generation and Energy
Marketing
Manitoba Hydro
No
City of Tallahassee
No
Tacoma Power
No
Public Utility District No.1 of
Snohomish County
No
American Transmission
Company
No
ReliabilityFirst
No
Idaho Power Company
No
City of Tallahassee
No
American Electric Power
Yes
AEP believes that it is likely that some of its business practices would need to at least
be modified as a result of this project
Response: Thank you for your comment.
CenterPoint Energy
Yes
Business practices will be needed to: 1. Document and monitor the generating plant
capacity at all Company owned generation interconnection facilities 2. Document and
monitor the largest generating unit located in the Balancing Authority 3. Document and
monitor the Company owned stations meeting the Applicability attributes described in
4.2.6 of PRC-005-3.
Consideration of Comments: Project 2007-17.2
19
Organization
Yes or No
Question 3 Comment
Response: Thank you for your comments.
Florida Municipal Power
Agency
Yes
Exelon and its Affiliates
Yes
Consideration of Comments: Project 2007-17.2
20
4. If you have any other comments on this SAR that you haven’t already mentioned, please provide them here:
Summary Consideration:
The comments were general in nature. Some comments were repeats from Question 1 while others pertained to the standard rather
than the SAR. However, the drafting team responded to all individual comments.
In response to a comment, the drafting team revised a sentence in the SAR’s “Need” statement from “Modifying the standard in this
fashion will impact Bulk Electric System (BES) reliability by assuring that the reclosing relays (installed to meet performance goals of
approved NERC Standards) are properly maintained so that they may be expected to perform properly.” to “Modifying the standard
in this fashion will assure that those reclosing relays that can affect the reliability of the Bulk Electric System are properly
maintained.”
Organization
Question 4 Comment
ACES Standards Collaborators
(1) We understand that NERC is obligated by law to address all FERC directives issued to them.
However, not all FERC directives require the development or revision of a reliability standard.
FERC has been clear that other alternatives may be used as long as they are equally effective and
efficient. NERC and the drafting team need to consider other alternatives that would produce an
equally effective method of ensuring that auto-reclosing relays will be maintained and tested.
The drafting team should consider a survey of all registered entities subject to the current PRC005 standard to see if they include auto-reclosers in their PSMT program. This issue goes back to
compliance - whether the entity needs to maintain documentation for each of these devices. A
guidance document may be an appropriate solution to handle this FERC directive.(2) Thank you
for the opportunity to comment.
Response: Thank you for your comments.
NERC, as well as other entities, provided comments in response to FERC NOPR discussions regarding requirements related to
maintenance of automatic reclosing, essentially proposing equally effective options. FERC, in response, directed that NERC
specifically include requirements related to maintenance of automatic reclosing within PRC-005.
Consideration of Comments: Project 2007-17.2
21
Organization
Question 4 Comment
Manitoba Hydro
(1) Brief Description of Proposed Standard Modifications/Actions - for completeness, add ‘(BES)’
after Bulk Electric System. (2) Need - capitalize ‘misoperation’ because it appears in the Glossary
of Terms. (3) Need - remove the words “Bulk Electric System” to leave only the acronym, BES
because this is the second instance of BES in the document.
Response: Thank you for your comments.
1. The SAR drafting team is not required to use acronyms for multiple appearances of terms. The SAR drafting team elected
to spell out “Bulk Electric System” wherever it appears.
2. The term, “misoperation” is used in a general context within the SAR, rather than the specific context addressed by the
NERC definition.
3. The SAR drafting team is not required to use acronyms for multiple appearances of terms. The SAR drafting team elected
to spell out “Bulk Electric System” wherever it appears.
Tennessee Valley Authority
1. Are reclosing relays considered "protective relays"?2. Are reclosing relays considered part of
the "protective system"?3. Is Table 1-3 applicable to CCVTs that feed only reclosing relays?4.
Does a "reclosing relay" include all relays used to perform all type of automatic reclosing actions,
i.e. sync check, dead line, dead bus, and blind reclosing?
Response: Thank you for your comments.
Comments 1-4: All of these considerations are left to the standard drafting team to address.
ReliabilityFirst
Can the SDT clarify whether high-speed automatic reclosing is covered within the scope of the
SAR?
Response: Thank you for your comments.
Yes, high-speed reclosing is covered within the scope of the SAR and left to the consideration of the standard drafting team.
FirstEnergy
FE supports the referenced SAR as stated.
Consideration of Comments: Project 2007-17.2
22
Organization
Question 4 Comment
Response: Thank you for your comment.
Dominion
Having reviewed, and generally agree with, the technical study performed jointly by the NERC
System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) and subsequently approved by the NERC Planning Committee. We
therefore support the OPTIONAL approach shown near the bottom of the SAR as we believe
would revise the standard in a way that applies new requirements only to those elements of the
protection system where reclosing is applied it been demonstrated to that an adverse impact on
the BES could occur if those element(s) are not included in one or more reliability standard
requirements.
Response: Thank you for your comments.
Southern Company: Southern
Company Services, Inc; Alabama
Power Company; Georgia Power
Company; Gulf Power Company;
Mississippi Power Company;
Southern Company Generation;
Southern Company Generation
and Energy Marketing
1. It seems out of order to be posting a draft SAR for informal comment at the same time
that the revised standard which is the topic of the SAR is posted for a formal comment
period.
2. Further, FERC has not approved PRC-005-2 yet. Any changes required by FERC would
affect the draft of PRC-005-3. The proposed standard modification seems premature
given that PRC-005-3 SAR is still in draft that PRC-005-2 is not yet approved.
Response: Thank you for your comments.
1. The SAR was previously posted for information only along with the third draft of PRC-005-2 in May, 2012. The Standards
Process Manual supports posting of a SAR for a comment period at the same time that a draft of the resulting standard is
posted for a formal comment period. “For SARs that are limited to addressing regulatory directives, or revisions to
Reliability Standards that have had some vetting in the industry, authorize posting the SAR for a 30-day informal comment
period with no requirement to provide a formal response to the comments received.”
2. The drafting team is acting in accordance with the schedule NERC provided to FERC, which outlines the timeframes by which
NERC will respond, through the standards drafting process, to the directives of FERC Order 758. Specifically regarding
Consideration of Comments: Project 2007-17.2
23
Organization
Question 4 Comment
reclose relays (Footnote 37), FERC directed NERC to: “By July 30, 2012, NERC should submit to the Commission either the
completed project which addresses the remaining issues consistent with this order, or an informational filing that provides
a schedule for how NERC will address such issues in the Project 2007-17 reinitiated efforts.”
SPP Standards Review Group
None
City of Tallahassee
None
City of Tallahassee
None
CenterPoint Energy
Page 2, Paragraph 2 of the “Need” section of the SAR includes a parenthetical “(installed to meet
performance goals of approved NERC Standards)”. Recommend deleting this parenthetical
statement as the SAMS/SPCS paper concluded on page 2 that “SAMS and SPCS have not
identified an application in which auto reclosing is used in coordination with a protection system
to meet the system performance requirements in a NERC Reliability Standard or in establishing
an IROL”.
Response: Thank you for your comments.
The drafting team revised the language to read as follows: “Modifying the standard in this fashion will assure that those reclosing
relays that can affect the reliability of the BES are properly maintained.”
Public Utility District No.1 of
Snohomish County
The Public Utility District No.1 of Snohomish County has reviewed and supports this Standard
Authorization Request and concluded that the revisions and modifications do not seem
impractical or technically unreasonable.
Response: Thank you for your comments.
Duke Energy
The SAR includes statements under “Goals” and “Detailed Description” that the defined term
Protection System might be revised as part of this project. Those statements should be removed
from the SAR. We strongly believe that the issue of maintenance and testing of any reclosing
relays which can affect reliable operation of the BES, can be addressed without attempting to
modify the definition of Protection System.
Consideration of Comments: Project 2007-17.2
24
Organization
Question 4 Comment
Response: Thank you for your comments.
The SAR does provide the drafting team the option to revise the definition of Protection System. The drafting team chose not to
modify the definition.
END OF REPORT
Consideration of Comments: Project 2007-17.2
25
Consideration of Comments
Project 2007-17.2 Protection System Maintenance and
Testing – Phase 2 (Reclosing Relays) PRC-005-3
The Project 2007-17.2 Drafting Team thanks all commenters who submitted comments on the PRC005-3 standard for Protection System Maintenance and Testing (Reclosing Relays). The standard was
posted for a 30-day formal comment period from April 5, 2013 through May 6, 2013. Stakeholders
were asked to provide feedback on the standard and associated documents through a special
electronic comment form. There were 36 sets of comments, including comments from approximately
143 different people from approximately 95 companies representing 8 of the 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration of all Comments Received
Definitions
Protection System Maintenance Program (PSMP):
Un-capitalized the term “Automatic Reclosing”
Automatic Reclosing
Minor revisions to provide clarity, the definition now reads:
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Segment
Capitalized the defined term “Component”
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Countable Event
Updated to incorporate reference to new Tables 4-1 through 4-2, and added the term “Protection
System” as a modifier of Misoperation for clarity.
Applicability
To add clarity, the drafting team revised 4.2.6 Facilities and each of the sections: 4.2.6.1, 4.2.6.2. and
4.2.6.3. The associated footnote was modified for congruence with the referenced sections.
Requirements
The Table reference in Requirement R1, Part 1.2 was updated to include Tables 4-1 through 4-2, and
the wording was revised for clarity.
The Table reference in Requirement R3 was updated to include Tables 4-1 through 4-2.
Measures:
The Table reference in Measure M1 was updated to include Tables 4-1 through 4-2.
Evidence Retention
The drafting team added the phrase “or Automatic Reclosing” for clarity.
VSLs
The Table references in the VSLs were updated to include Tables 4-1 through 4-2.
Version History
The previous version history of PRC-005 was added for completeness.
Tables
The Tables were updated to accommodate the addition of Tables 4-1 through 4-2.
Attachment A
Attachment A was updated to include Tables 4-1 through 4-2.
Supplementary Reference and FAQ
Additional content was added to reflect changes in the standard.
Additional Implementation Plan
A second Implementation Plan was developed to address generation changes in the Balancing
Authority Area that result in additional locations becoming subject to the Applicability of PRC-005-3.
The document titled: “Implementation Plan for Newly identified Automatic Reclosing Components due
to generation changes in the Balancing Authority Area”, is posted with the draft standard.
Consideration of Comments: Project 2007-17.2
2
Unresolved Minority Views
Several commenters suggested making general changes to PRC-005-2. The drafting team
responded that the SAR precludes the drafting team from making general revisions to the
standard in content or arrangement, only allowing modifications to explicitly address the
maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk
Electric System. The drafting team did not make any of the suggested changes.
Several commenters were concerned about initiating the project to establish PRC-005-3 before
PRC-005-2 is FERC approved. The drafting team explained that they are acting in accordance
with the schedule provide to FERC in an informational filing submitted by NERC, in response to
FERC Order 758 which stated: “By July 30, 2012, NERC should submit to the Commission either
the completed project which addresses the remaining issues consistent with this order, or an
informational filing that provides a schedule for how NERC will address such issues in the
Project 2007-17 reinitiated efforts.” In the Order, FERC accepted NERC’s commitment to
address the maintenance and testing of reclosing relays that can affect the reliable operation of
the Bulk-Power System within the standards development process. Phase 2 (Reclosing Relays)
of Project 2007-17 Protection System Maintenance and Testing was initiated to develop PRC005-3 and satisfy NERC’s commitment to the FERC.
A few commenters questioned the complexity of the Implementation Plan for PRC-005-3 which
includes the Protection System aspects of PRC-005-2 and adds the new aspects of Automatic
Reclosing from PRC-005-3. The plan addresses the implementation of the PRC-005-2
requirements based on the approval date of PRC-005-2 and adds the implementation of the
revised requirements that include Automatic Reclosing based on the approval date of PRC-0053. This approach provides clarity regarding the implementation dates for maintenance of
Protection System and Automatic Reclosing Components. The drafting team crafted the
Implementation Plan with guidance from NERC legal staff and believes the Implementation Plan
is clear once carefully reviewed.
Index to Questions, Comments, and Responses
1.
The drafting team modified PRC-005-2 and its associated Supplementary Reference and FAQ
document to address Automatic Reclosing as directed in FERC Order No. 758. Do you agree with
these changes? If not, please provide specific suggestions for improvement............................... 12
Consideration of Comments: Project 2007-17.2
3
2.
The drafting team developed an Implementation Plan for PRC-005-3 based on the
Implementation Plan for PRC-005-2 to address the addition of Automatic Reclosing. Do you
agree with the implementation plan regarding Automatic Reclosing? If not, please provide
specific suggestions for improvement. ............................................................................45
Consideration of Comments: Project 2007-17.2
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Louis Slade
Additional Organization
Dominion
NERC Compliance Policy
NPCC 1, 3, 5, 6
2. Randi Heise
NERC Compliance Policy
RFC
1, 3, 5, 6
3. Connie Lowe
NERC Compliance Policy
SERC
1, 3, 5, 6
4. Chip Humphrey
Fossil & Hydro
NPCC 5
5. Sean Iseminger
Fossil & Hydro
RFC
5
6. Matt Woodzell
Fossil & Hydro
SERC
5
7. Jeff Bailey
Nuclear
5
8. Michael Crowley
Electic Transmission Compliance SERC
1, 3
Group
Robert Rhodes
X
SPP Standards Review Group
3
X
Region Segment Selection
1. Mike Garton
2.
2
X
4
5
X
6
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Bud Averill
Grand River Dam Authority SPP
1, 3, 5
2. Timothy Bobb
Westar Energy
SPP
1, 3, 5, 6
3. Afshin Jalilzadeh
Westar Energy
SPP
1, 3, 5, 6
4. Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
5. Bo Jones
Westar Energy
SPP
1, 3, 5, 6
6. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
7. Russ Matzke
Westar Energy
SPP
1, 3, 5, 6
3.
Group
David Thorne
Pepco Holdings Inc & Affiliates
X
X
Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley
Delmarva Power & Light Co RFC
1
2. Carlton Bradshaw
Delmarva Power & Light Co RFC
1, 3
4.
Group
David Greene
SERC Protection and Controls
Subcommittee
Additional Member Additional Organization Region Segment Selection
1.
Paul Nauert
Ameren
SERC
2.
John Miller
GTC
SERC
3.
Phil Winston
Southern Company
SERC
4.
Bridget Coffman
Santee Cooper
SERC
5.
Steve Edwards
Dominion VP
SERC
6.
Charlie Fink
Entergy
SERC
7.
Joel Masters
SCE&G
SERC
8.
Jay Farrington
PowerSouth
SERC
9.
David Fountain
Duke Energy
SERC
10. Flavio Graciaa
Southern Company
SERC
11. Jerry Blackley
Duke Energy
SERC
12. David Greene
SERC RRO
SERC
5.
Russ Mountjoy
Group
MRO NERC Standards Review Forum
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Alice Ireland
Xcel
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
Consideration of Comments: Project 2007-17.2
6
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Dan Inman
MPC
MRO
1, 3, 5, 6
4.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
5.
Kayleigh Wilkerson LES
MRO
1, 3, 5, 6
6.
Jodi Jensen
WAPA
MRO
1, 6
7.
Joseph DePoorter
MGE
MRO
3, 4, 5, 6
8.
Ken Goldsmith
ALTW
MRO
4
9.
Lee Kittleson
OTP
MRO
1, 3, 5
10. Mahmood Safi
OPPD
MRO
1, 3, 5, 6
11. Marie Knox
MISO
MRO
2
12. Mike Brytowski
GRE
MRO
1, 3, 5, 6
13. Scott Bos
MPW
MRO
1, 3, 5, 6
14. Scott Nickels
RPU
MRO
4
15. Terry Harbour
MEC
MRO
1, 3, 5, 6
16. Tom Breene
WPS
MRO
3, 4, 5, 6
17. Tony Eddleman
NPPD
MRO
1, 3, 5
6.
Guy Zito
Group
Additional Member
2
3
4
5
Northeast Power Coordinating Council
Additional Organization
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris De Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Michael Jones
National Grid
NPCC 1
10. David Kiguel
Hydro One Networks Inc.
NPCC 1
11. Christina Koncz
PSEG Power LLC
NPCC 5
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Si-Truc Phan
HydroQuebec TransEnergie
NPCC 1
15. Silvia Parada Mitchell NextEra Energy, LLC
Consideration of Comments: Project 2007-17.2
7
8
9
10
X
Region Segment Selection
1.
6
NPCC 5
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
19. Brian Robinson
Utility Services
NPCC 8
20. Brian Shanahan
National Grid
NPCC 1
21. Don Weaver
New Brunswick System Operator
NPCC 2
22. Wayne Sipperly
New York Power Authority
NPCC 5
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
7.
Sasa Maljukan
Group
2
3
4
5
6
5
Hydro One Networks Inc.
X
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks Inc. NPCC 1
2. Paul Difilippo
Hydro One Networks Inc. NPCC 1
8.
Group
Nicholas A. Poluch
Additional
Member
PPL Corporation NERC Registered Affiliates
Additional Organization
PPL Electric Utilities Corporation
Region
X
X
X
Segment
Selection
1.
Brenda L. Truhe
RFC
1
2.
Karl B. Ingebrigtson LG&E and KU Services Company
SERC
3
3.
PPL Generation, LLC on behalf of its Supply NERC Registered
Annette M. Bannon
Entities
RFC
5
4.
X
WECC 5
5.
MRO
6
6.
Elizabeth A. Davis
PPL EnergyPlus, LLC
NPCC
6
7.
SERC
6
8.
SPP
6
9.
RFC
6
10.
WECC 6
11.
6
9.
Group
Greg Campoli
ISO RTO Council Standards Review
Committee
X
Additional Member Additional Organization Region Segment Selection
1. Steve Myers
ERCOT
ERCOT 2
Consideration of Comments: Project 2007-17.2
8
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Ben Li
IESO
NPCC
2
3. Matt Goldberg
ISONE
NPCC
2
4. Bill Phillips
MISO
MRO
2
5. Tom Bowe
PJM
RFC
2
6. Charles Yeung
SPP
SPP
2
10.
Group
Colby Bellville
Duke Energy
2
3
X
X
X
X
X
X
4
5
6
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
11.
Group
Larry Raczkowski
FirstEnergy
Additional Member Additional Organization Region Segment Selection
1. William Smith
FirstEnergy Corp
RFC
1
2. Cindy Stewart
FirstEnergy Corp
RFC
3
3. Doug Hohlbaugh
Ohio Edison
RFC
4
4. Ken Dresner
FirstEnergy Solutions
RFC
5
5. Kevin Querry
FirstEnergy Solutions
RFC
6
12.
Group
Frank Gaffney
Florida Municipal Power Agency
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
3
13.
Group
FRCC
Jason Marshall
Additional Member
ACES Standards Collaborators
Additional Organization
X
Region Segment Selection
1. Shari Heino
Brazos Electric Power Cooperative
ERCOT 1, 5
2. Tom Alban
Buckeye Power
RFC
3. Kevin Lyons
Central Iowa Power Cooperative
MRO
Consideration of Comments: Project 2007-17.2
3, 4
9
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Megan Wagner
Sunflower Electric Power Corporation SPP
5. John Shaver
Arizona Electric Power Cooperative
6. John Shaver
Southwest Transmission Cooperative WECC 1
7. Scott Brame
NCEMC
14.
Group
Jamison Dye
Additional Member
Additional Organization
SERC
5
6
WECC 1
PSC Technical Svcs
WECC 1
3. Brenda Vasbinder
Work Planning and Evaluation WECC 1
X
X
X
X
X
X
X
X
X
X
X
X
Individual
Marcus Pelt
17.
Individual
Doug Jensen
Vandolah Power Company
18.
Individual
Herb Schrayshuen
Self
19.
Individual
David Ramkalawan
Individual
Michelle R. D'Antuono
OPG
Ingleside Cogeneration LP (Occidental
Chemical Corporation)
21.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
22.
Individual
John Bee
exelon and its Affiliates
X
X
X
23.
Individual
David Jendras
Ameren
X
X
X
X
24.
Individual
Chris Mattson
Tacoma Power
X
X
X
X
25.
Individual
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
X
26.
Individual
Thomas Foltz
American Electric Power
X
X
X
X
27.
Individual
Brad Harris
CenterPoint Energy
X
20.
8
1, 3, 4, 5
PacifiCorp
Southern Company - Southern Company
Services, Inc.; Alabama Power
Company;Georgia Power Company;
Mississippi Power Company; Gulf Power
Company; Southern Company Generation;
Southern Company Generation and Energy
Marketing
16.
7
1
Bonneville Power Administration
SPC Technical Svcs
Ryan Millard
4
Region Segment Selection
2. Jason Burt
Individual
3
WECC 4, 5
1. Heather Laslo
15.
2
Consideration of Comments: Project 2007-17.2
X
X
X
X
X
X
10
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
28.
Andrew Z. Pusztai
American Transmission Company
Individual
30. Individual
Bill Fowler
Anthony Jablonski
City of Tallahassee
ReliabilityFirst
31.
Individual
Cole Brodine
Nebraska Public Power District
32.
Individual
Oliver Burke
Entergy Services, Inc.
X
X
33.
Individual
Kevin Luke
Georgia Transmission Organization
X
34.
Individual
Michael Falvo
Independent Electricity System Operator
35.
Individual
Jonathan Meyer
Idaho Power Company
X
36.
Individual
Scott Langston
City of Tallahassee
X
Consideration of Comments: Project 2007-17.2
3
4
5
6
7
8
9
10
X
Individual
29.
2
X
X
X
X
X
X
X
X
11
1. The drafting team modified PRC-005-2 and its associated Supplementary Reference and FAQ document to address Automatic
Reclosing as directed in FERC Order No. 758. Do you agree with these changes? If not, please provide specific suggestions for
improvement.
Summary Consideration:
Numerous commenters agreed with the proposed changes.
Several commenters had concerns regarding the definition of Automatic Reclosing. The drafting team revised the definition to read:
“Includes the following Components:
•
Reclosing relay
•
Control circuitry associated with the reclosing relay.”
Several commenters suggested making general changes to PRC-005-2. The drafting team responded that the SAR precludes the
drafting team from making general revisions to the standard in content or arrangement, only allowing modifications to explicitly
address the maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk Electric System. The
drafting team did not make any of the suggested changes.
Several commenters requested the Applicability sections pertaining to Automatic Reclosing be revised for better specificity. The
drafting team responded by revising each of the sections 4.2.6.1, 4.2.6.2, and 4.2.6.3. The drafting team revised Applicability 4.2.6.1
to specify that the relevant “Automatic Reclosing is applied on the terminals of Elements connected to the BES bus located…”and
4.2.6.2 to specify that the “Automatic Reclosing is applied on the terminals of all BES Elements” for more clarity. The drafting team
also revised 4.2.6.1 and the footnote to specify that ‘gross’ capacity should be used both for individual units and for plants.
Furthermore, the drafting team revised sections 4.2.6.1 and the footnote to clarify that the applicable locations are where “the
largest BES generating unit within the Balancing Authority Area...” Applicability 4.2.6.3 now reads: “Automatic Reclosing applied as
an integral part of an SPS specified in Section 4.2.4.”
Several commenters had questions regarding the meaning of “trip-close-trip” in the Applicability footnote. The drafting team
explained that this addresses conditions where a failure in the Automatic Reclosing results in an immediate close of the breaker
followed by an immediate trip, following the initial fault. The drafting team noted that the affected TO, GO, and DP would be
responsible for performing the evaluation described in the footnote if they desire to exclude otherwise-applicable facilities.
Consideration of Comments: Project 2007-17.2
12
Several commenters were concerned about initiating the project to establish PRC-005-3 before PRC-005-2 is FERC approved. The
drafting team explained that they are acting in accordance with the schedule provide to FERC in an informational filing submitted by
NERC, in response to FERC Order 758 which stated: “By July 30, 2012, NERC should submit to the Commission either the completed
project which addresses the remaining issues consistent with this order, or an informational filing that provides a schedule for how
NERC will address such issues in the Project 2007-17 reinitiated efforts.” In the Order, FERC accepted NERC’s commitment to address
the maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power System within the standards
development process. Phase 2 (Reclosing Relays) of Project 2007-17 Protection System Maintenance and Testing was initiated to
develop PRC-005-3 and satisfy NERC’s commitment to the FERC.
Several commenters had concerns related to applicable facilities changing because of generation changes within the Balancing
Authority Area. The drafting team developed a second implementation plan: “Implementation Plan for Newly identified Automatic
Reclosing Components due to generation changes in the Balancing Authority Area”, to alleviate these concerns.
A number of commenters questioned how they would be aware of the largest generator in the Balancing Authority Area. The
drafting team explained that the Balancing Authority would have this information and would be able to provide it to them.
Updates were made and additional content was added to the Supplementary Reference and FAQ document to reflect changes in the
standard.
Organization
Yes or No
Manitoba Hydro
No
Question 1 Comment
(1) Definition of Terms Used in Standard - statements in this section are contradictory.
Please clarify if “When the standard becomes effective, these defined terms will be
removed from the individual standard and added to the Glossary.” or whether “The
following terms are defined for use only within PRC-005-3, and should remain with the
standard upon approval rather than being moved to the Glossary of Terms.” Why are
the following terms defined for use only within PRC-005-3 rather than being moved to
the Glossary of Terms? (Automatic Reclosing, Unresolved Maintenance Issue, Segment,
Component Type, Component and Countable Event). (2) Definitions of Terms Used in
Standard, Protection System Maintenance Program (PSMP) (NERC Board of Trustees
Approved Definition) - for clarity, the word ‘is’ in the following sentence,
“...components is restored.” should be changed to “...components are restored.”
Consideration of Comments: Project 2007-17.2
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Yes or No
Question 1 Comment
Additionally, MH assumes that the words “NERC Board of Trustees Approved
Definition” will be removed from the final version of the standard and that wording
was provided for informational purposes only in the circulation of the standard. (3)
Definitions of Terms Used in Standard, Automatic Reclosing - for clarity, we suggest
beginning the definition with the following words ‘includes the following’. (4)
Definitions of Terms Used in Standard, Segment - please clarify if the reference to
Components in this definition is intended to be to the defined term “Components”? If
so, the word should be capitalized at the end of this definition. If this is not the
intension, then an alternate word should be chosen to avoid confusion. (5) Definitions
of Terms Used in Standard, Countable Event - the words “included in” from the last
sentence of the definition are unnecessary and should be removed. (6) A.
Introduction, 3. Purpose - for clarity, consider revising the purpose to read “To
document and implement programs for the maintenance of all Protection Systems and
Automatic Reclosing affecting the reliability of the Bulk Electric System (BES) for
maintaining functional operation”. (7) 4.2.6 Automatic Reclosing - for section
consistency, the words ‘applied on BES Elements, including:’ should be added to 4.2.6.
Additionally, sections 4.2.6.1 and 4.2.6.2 should be rewritten as follows: 4.2.6.1
“Automatic Reclosing Applied on BES Elements at generating plant
substations....”4.2.6.2 “Automatic Reclosing Applied on BES Elements at substations....”
(8) 4.2 footnote 1 - reference is made to equipment owner which is an undefined term.
For clarity, consider referring to the Responsible Entity instead. In addition, some
words seem to be missing which could provide some guidance as to what is being
compared. For example, is it the intent of meaning - “does not result in a total loss of
generation in the Interconnection exceeding the generation of the largest unit within
the Balancing Authority Area....”? (9) 4.2.6.3 - the words ‘integral part’ are very
subjective and may be difficult to assess. (10) 5. Effective Date - for completeness and
consistency with other standards, text from the implementation plan should be moved
to the standard Effective Date section. (11) 3. Measures - use the acronym for
Protection System Maintenance Program, PSMP in M1 and M4 since this is not the first
instance of this definition. (12) 1.3. Evidence Retention - use the acronym for
Protection System Maintenance Program, PSMP in the third paragraph of this section
Consideration of Comments: Project 2007-17.2
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Organization
Yes or No
Question 1 Comment
because this is not the first instance of this definition. (13) PRC-005 - Attachment A,
Criteria for a Performance-Based Protection System Maintenance Program - for
completeness, add the acronym (PSMP) after the title. (14) Section D, Compliance, 1.1
- the paraphrased definition of ‘Compliance Enforcement Authority’ from the Rules of
Procedure is not the standard language for this section. Is there a reason that the
standard CEA language is not being used? (15) Section D, Compliance, 1.3 - this section
was not updated to reference Automatic Reclosing. (16) Protection System
Maintenance Program is defined in the standard as PMSP but then inconsistently
referenced using both the full term and the acronym. (17) R1 - there are inconsistent
references throughout the requirements made to ‘Protection System and Automatic
Closing Component Types’ vs. ‘Protection System Component Type and Automatic
Reclosing Components’ vs. ‘Protection System and Automatic Reclosing Components’.
Please clarify if this is the intent or consider correcting. (18) R2, R3 and R4 - there
appears to be inconsistency in the drafting of R1, R2 and R3 as to what is required.
There is no requirement to “implement and follow” a PMSP within the time based
program the way there is for the performance based program. (19) R5 - MH believes
that the requirement should be to make efforts, not demonstrate efforts.
Demonstrating or providing evidence of the efforts would be the measure. (20) VSLs,
R1 - the Requirement refers to both Protection System and Automatic Reclosing
Components while the VSL refers only to Components. (21) VSLS, R2 - the wording of
the VSL for this requirement does not seem consistent with the wording of
Attachment A. (22) VSLS, R3 and R4 - rather than writing ‘more than x% but y% or
less’, it would be clearer to write ‘more than x% but less than y%’.
Response: Thank you for your comment.
1. (a) The first statement originally referred to both the revised definition of Protection System and the term Protection
System Maintenance Program (PSMP). When FERC approved the Protection System definition revision, the drafting team
removed that term from this section, but failed to change the plural reference to singular. This has now been corrected in
the standard.
(b) Terms included in the NERC Glossary of Terms carry their definition regardless of the standard in which they are used.
Consideration of Comments: Project 2007-17.2
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Yes or No
Question 1 Comment
The drafting team believes the definitions of the terms slated to remain with PRC-005 would not be appropriate for use in
other standards.
2. (a) The use of “is restored” is correct. The reference is “proper operation… is restored”, not that components are restored.
(b) The original definition of PSMP will be removed from PRC-005-2 following FERC approval; the revised definition of
PSMP (adding Automatic Reclosing) will be removed from PRC-005-3 when that standard is FERC approved. The references
to ‘NERC Board of Trustees Approved Definition’ will be removed from the standards upon FERC approval.
3. The drafting team revised the standard to address your comment by adding “Includes the following Components:”.
4. The drafting team corrected the non-capitalized term.
5. The drafting team agrees with your suggestion but is precluded by the scope of the SAR for this project to make general
content changes.
6. The drafting team is precluded by the scope of the SAR for this project to make general content changes.
7. The drafting team revised the standard in consideration of your comment.
8. Responsible Entity is not a defined term and ‘equipment owner’ is self explanatory, therefore, the drafting team did not
make the suggested change. In response to your other comment, the drafting team revised the footnote to provide more
clarity.
9. The drafting team believes the use of “integral part” (in·te·gral: essential to completeness – Merriam-Webster) within the
context of 4.2.6.3 clearly conveys the standard would apply to Automatic Reclosing used as an integral part of a Special
Protection System.
10. The drafting team believes that entities need to consider the Implementation Plan in its entirety rather than simply
knowing the Effective Date for PRC-005-3.
11. The use of acronyms is optional. The drafting team chose not to in the instances cited.
12. The use of acronyms is optional. The drafting team chose not to in the instances cited.
13. The use of acronyms is optional. The drafting team chose not to in the instances cited.
14. This is the boiler plate CEA language currently used in all reliability standards.
15. Thank you. The drafting team made the revision to the standard.
16. The use of acronyms is optional. The drafting team chose not to in the instances cited.
17. The drafting team reviewed the use of the terms and made changes as needed.
18. Requirement R3 establishes that entities with components addressed by a time-based PSMP must maintain those
components “in accordance with the minimum maintenance activities and maximum maintenance intervals prescribed
within Tables 1-1 through 1-5, Table 2, Table 3, and Table 4”. Requirement (R3) effectively constitutes “implementing and
Consideration of Comments: Project 2007-17.2
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Organization
Yes or No
Question 1 Comment
following” the PSMP.
19. The drafting team is precluded by the scope of the SAR for this project to make general content changes.
20. The drafting team revised Requirement R1 such that the VSL for Requirement R1 is now consistent with the requirement.
21. The drafting team believes the language of the VSL for R2 is correctly composed and consistent with the criteria for a
Performance-Based Maintenance Program provided in Attachment A.
22. The drafting team is precluded by the scope of the SAR for this project to make general content changes. Furthermore,
your suggested change would leave a gap in the phased VSL approach.
ACES Standards Collaborators
No
(1) While we believe the standard should not be modified until FERC rules on version 2
of PRC-005, we appreciate that the drafting team adopted the recommendations of the
Planning Committee in limiting the applicable reclosing relays to only those that may
impact reliability. Limiting applicability to only those auto-reclosing relays that are
close to large generating stations or that are applied as part of an SPS appears to fully
meet the intent of the FERC directive. This limited applicability will help avoid the
negative reliability impacts that would occur as a result of expanding applicability. If all
auto-reclosing relays were included, the standard would detract resources away from
reliability needs to unnecessary documentation. (2) We have a concern with the “Auto
Reclosing” definition being proposed in this draft standard. Some parts of the
definition may require further clarification and may be vague. What does “such as
anti-pump and ‘various’ interlock circuits” mean? Will auditors and industry subject
matter experts understand them in the same way? “Various” is not a clear adjective to
describe interlock circuits. We recommend revising the entire definition to clearly
state the scope of the devices (possibly even the IEEE numbers).(3) There are concerns
with the supplementary reference document because it assumes that PRC-005-2 will
be approved by the Commission. This assumption is presumptuous and should not
reflect any Commission rulings that have yet to occur. We recommend stating the
current status of the PRC-005-2 project, which was filed with FERC in February 2013
and is pending the Commission’s approval. Statements such as “PRC-005-2 ‘replaced’
PRC-011” should be modified to “PRC-005-2 will replace PRC-011 upon approval from
FERC,” or something similar. (4) We suggest additional clarification may be needed for
section 4.2.6.1 regarding applicability of auto-reclosing relays. This section states that
Consideration of Comments: Project 2007-17.2
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Organization
Yes or No
Question 1 Comment
the standard will apply to auto-reclosing relays implemented at the generating plant
substation where installed generating plant capacity is greater than the largest
generating unit in the BA. We presume this was selected because the largest
generating unit is often the most severe single contingency and establishes the amount
of contingency reserves that must be carried. If our assumption is correct, we would
suggest that the applicability may need to be based on the largest resource in a
Reserve Sharing Group (RSG) or BA. There is at least one large BA in the Eastern
Interconnection where the largest resource is actually the loss of a 500-kV line that
triggers a generation runback scheme. If a BA participates in an RSG, the BA would
have access to contingency reserves that would be carried by the group and, thus, the
only time a call for contingency reserves would exceed the amount carried would be
when the generation loss is greater than the largest resource in the RSG.
Response: Thank you for your comment.
1. The drafting team thanks you for your support. The drafting team is acting in accordance with the schedule NERC provided
to FERC, which outlines the timeframes by which NERC will respond, through the standards drafting process, to the
directives of FERC Order 758. Specifically regarding reclosing relays (Footnote 37), FERC directed NERC to: “By July 30,
2012, NERC should submit to the Commission either the completed project which addresses the remaining issues
consistent with this order, or an informational filing that provides a schedule for how NERC will address such issues in the
Project 2007-17 reinitiated efforts.” Providing the schedule for addressing both reclosing relays and relays that do not
respond to electrical quantities addressed this requirement of FERC Order 758.
2. The drafting team removed the exclusionary language from the definition of Automatic Reclosing and added discussion to
the Supplementary Reference and FAQ document.
3. The Supplementary Reference and FAQ document provided with this posting is for PRC-005-3. Therefore, this document
will only be relevant when PRC-005-3 is approved by FERC. The drafting team has updated the Introduction and Summary
section of the PRC-005-3 Supplementary Reference and FAQ document to provide a summary of Order 758 that are driving
the revisions to PRC-005-2.
4. The language in the Applicability section of the draft standard reflects the recommendations provided in the SPCS-SAMS
Order 758 Autoreclosing Report. The technical authors (SPCS and SAMS) considered alternative language before making
the final recommendation.
Consideration of Comments: Project 2007-17.2
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Organization
Yes or No
Nebraska Public Power District No
Question 1 Comment
*4.2.6.1 - Is the largest generator included or excluded? Based on the definition, the
largest generator is not larger than the largest generator, so it would not be
included.*Confirm other input to Automatic reclosing Relays are NOT included
(including but not limited to...):Synch check relays.Voltage sensing devicesPlease
explain or clarify better what the SPS includes, spefically what does “integral part”
mean?Please explain what a minimum trip-close-trip time delay is and how this
exclusion would work.Please clarify which circuitry is applicable. An example would be
A/B contacts, are these included or not?
Response: Thank you for your comment.
1. Generators are neither included nor excluded by Applicability section 4.2.6.1., as PRC-005-3 applies to Protection System
and Automatic Reclosing equipment, not the lines or generators themselves. This section specifically refers to Automatic
Reclosing equipment applied on the terminals of Elements connected to the BES bus located at generating plant
substations where the total installed gross generating plant capacity is greater than the gross capacity of the largest BES
[individual] generating unit within the Balancing Authority Area. The largest single generator is excluded if it is the only
generator at the plant because the system is planned and operated to withstand the loss of that generator.
2. The definition of Automatic Reclosing provided in PRC-005-3 refers to specific components of automatic reclosing (reclose
relays and control circuitry). By definition, therefore, any component not included in the definition, such as the examples
you provided (synch check relays and voltage sensing devices) would not be considered components of Automatic
Reclosing.
3. Automatic reclosing components that are an “integral part” of a Special Protection System (SPS) would be Automatic
Reclosing that is necessary for the SPS to function properly and provide the outcome intended. If failure or inadvertent
operation of Automatic Reclosing keeps an SPS from performing its intended function, the requirements of PRC-005-3
would apply to that equipment.
4. Trip-close-trip includes the time it takes from initiation of the trip signal through the initiation of a reclose signal and
subsequent breaker trip (the Fault is still there after the initial trip). This includes the time it takes for the breaker contacts
to open (trip time), plus the time it takes for the breaker to close back in (reclose time) and immediately trip out again to
clear the fault (second trip time). The entity would need to evaluate if twice the normal clearing time is less than the
critical clearing time for the generator.
5. The standard requires verification that Automatic Reclosing, upon initiation, does not issue a premature closing command.
Consideration of Comments: Project 2007-17.2
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Organization
Yes or No
Question 1 Comment
Specific activities have been added to Table 4 regarding close control circuitry associated with an SPS.
PPL Corporation NERC
Registered Affiliates
No
1) There are currently two NERC approved projects filed at FERC (PRC-005-1.1b and
PRC-005-2). NERC should consider waiting to proceed with this project until the
current projects are ruled on and FERC provides further direction. 2) For 4.2.6, for
reclosing capability, it is unclear what functionality is to be tested. Please define.3) For
PRC-005-3 section 4.2.6.2, please provide the technical basis for this application of the
Standard. Specifically, this application states for Automatic Reclosing: “Applied on BES
Elements at substations one bus away from generating plants specified in section
4.2.6.1 when the substation is less than 10 circuit miles from the generating plant
substation.” Please provide the technical basis/reasoning for the 10-mile criteria. At a
recent North American Transmission Forum Workshop on Protection System
Maintenance Program it was implied that the 10 mile rule is for cases where a
generator has a short connection to another company’s substation. Please clarify if
this is the case.4) For PRC-005-3 section R1, consider adding the following language
that is used for PRC-005-1.1b “each Generator Owner that owns a generation or
generator interconnection Facility Protection System...” This is NERC-approved
language that has been through the standards development process and has technical
justification through Project 2010-07.5) Please provide the technical basis for R1.1
which requires battery testing for DC Supply Component Type Protection Systems to be
time based. 6) Table 1-2 of PRC-005-3 requires functional testing of non-monitored
communication systems on a 4 month cycle. Please specify NERC’s criteria for the
functional testing (what attributes to be tested). Additionally, specifically define
monitoring criteria and data intervals for continuous monitoring of communications
systems (to see if check back (fail/no fail) monitoring is adequate).
Response: Thank you for your comment.
1. The drafting team is acting in accordance with the schedule NERC provided to FERC, which outlines the timeframes by
which NERC will respond, through the standards drafting process, to the directives of FERC Order 758. Specifically
regarding reclosing relays (Footnote 37), FERC directed NERC to: “By July 30, 2012, NERC should submit to the Commission
Consideration of Comments: Project 2007-17.2
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Organization
2.
3.
4.
5.
6.
Yes or No
Question 1 Comment
either the completed project which addresses the remaining issues consistent with this order, or an informational filing
that provides a schedule for how NERC will address such issues in the Project 2007-17 reinitiated efforts.” Providing the
schedule for addressing both reclosing relays and relays that do not respond to electrical quantities addressed this
requirement of FERC Order 758.
The specific functionality is defined within the requirements, specifically within Table 4.
The language in the Applicability section of the draft standard PRC-005-3 reflects the recommendations provided in the
Planning Committee-approved guidance document titled, “Considerations for Maintenance and Testing of Autoreclosing
Schemes”. This document was jointly composed by the NERC System Analysis and Modeling Subcommittee (SAMS) and
the System Protection and Control Subcommittee (SPCS) to support the Project 2007-17.2 drafting team in the
development of the requirements for PRC-005-3. Technical justification for the final recommendations provided in the
document can be found on page 12 of the report.
The drafting team is precluded by the scope of the SAR for this project to make general content changes.
Please refer to the Supplementary Reference and FAQ document that was posted with the final, approved version of PRC005-2 for more detailed information regarding battery maintenance and testing requirements and the reason for their
exclusion from a Perform Based Maintenance (PBM) program (Section 9.2, Frequently Asked Questions, “Why are
batteries excluded from PBM? What about exclusion of batteries from condition based maintenance?”).
The drafting team is precluded by the scope of the SAR for this project to make general content changes.
FirstEnergy
No
1. FE supports the technical aspects and requirements of the standard.2. FE is
questioning the accuracy of the red-lining in this document. Many of the definitions
were reflected as “new” when in fact only minor changes were made. 3. FE also
questions why the drafting team is proposing deletions in the Revision History of the
standard. Complete and accurate revision history is information that needs to be
retained for future reference.
Response: Thank you for your comment.
1) Thank you for your support
2) The observation is correct. The version submitted by the drafting team reflected only the addition of ‘reclosing’ language.
Using the “Compare” function in Microsoft Word resulted in the redlining of the entire definition(s).
3) The drafting team agrees and has included the complete Revision History in this draft of the standard.
Consideration of Comments: Project 2007-17.2
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Organization
Ameren
Yes or No
No
Question 1 Comment
Ameren concurs with and also incorporates the SERC PCS comment regarding the
interval for Automatic Reclosing exclusion studies by this reference.Ameren specific
comments are:(1) We request that the SDT add a FAQ: “Automatic Reclosing is a
control, not a protective function; why then is Automatic Reclosing maintenance
included in the Protection System Maintenance Program (PSMP)?” Answer: “Yes,
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes its function from the
Protection System. Automatic Reclosing is included in the PSMP because it is more
concise than creating a parallel and essentially identical ‘Control System Maintenance
Program’ for the two Automatic Reclosing component types.”(2) We request that the
SDT add a FAQ: “Our maintenance practice consists of initiating the Automatic
Reclosing relay and confirming the breaker closes properly. This practice verifies the
Control circuitry associated with Automatic Reclosing including the close coil. Do you
agree?” Answer: “Yes, since the breaker does successfully close in your practice. The
intent of the Unmonitored Control circuitry Maintenance Activity is for the entity to
functionally prove the Automatic Reclosing control path is intact through the breaker
close coil.”(3) We request that the SDT revise the Countable Event definition because
as written it incorrectly implies that an Automatic Reclosing failure is a Misoperation.
We believe that the Automatic Reclosing exclusion needs to be moved to a different
sentence.(4) We request that the SDT add a FAQ: “Why was a close-in three phase fault
present for twice the normal clearing time chosen for the Automatic Reclosing
exclusion? It exceeds TPL requirements and ignores the breaker closing time in a tripclose-trip sequence, thus making the exclusion harder to attain.” Answer: “This test
was chosen intentionally to err on the side of conservatism.”(5) We request that the
SDT augment the FAQ 2.4.1 to include “IEEE Device No. 79” in referring to the
Automatic Reclosing relay because this helps clarify the scope.
Response: Thank you for your comments.
1) The Supplementary Reference and FAQ document was updated based on your input (Clause 15.8.1).
2) The Supplementary Reference and FAQ document was updated based on your input (Clause 15.8.1).
Consideration of Comments: Project 2007-17.2
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Question 1 Comment
3) The definition of “Countable Event” was modified to clarify that Misoperations are associated with Protection Systems.
4) The Supplementary Reference and FAQ document was updated based on your input (Clause 15.8.1).
5) The drafting team elected not to include the IEEE Device No 79 as an explicit reference within the Supplementary
Reference and FAQ document.
Independent Electricity
System Operator
No
Comments: We only agree with the scope presented in the SAR. We do not agree with
the proposed changes, as stated below.We suggest that the maintenance for
Automatic Reclosing installed on the lines defined at Section 4.2.1 could be done at the
same time with the maintenance of Protection Systems installed on those lines.
Similarly, the maintenance for Automatic Reclosing used as an integral part of a SPS
defined in Section 4.2.4 could be done at the same time with the maintenance for SPS.
Please see the rational below.The report attached as a supporting document mentions
as a credible failure “a close signal is issued with no delay or less delay than is
intended”. This failure should be classified as either a normal contingency or an
extreme contingency, to be consistent with the TPL standards contingency
classification. Section 4.2.6.1 states that Automatic Reclosing should be maintained “at
generating plants substations where the total installed capacity is greater than the
capacity of the largest generating unit within the Balancing Authority”. However,
depending on the assumptions (how the system is stressed, extreme weather, etc.) and
specific configurations, there may be other locations, where if the sequential three
phase fault described in the Footnote 1 is applied, the total generation loss could be
greater than the largest unit within the Balancing Authorities. The standard lacks a
common methodology for testing sequential three phase faults described in the
Footnote 1: o The standard does not specify the conditions (extreme weather base
case, extreme contingencies base case, how the generators are dispatched, etc.) or
what would be the time delay between the first and second fault. All these conditions
may affect the total generation loss.o The 10 circuit-miles criteria should be confirmed
with the Planning Coordinators.o Depending on the location of the line being tested,
different neighboring entities may be involved.o There should be a process in place to
update the list of the Automatic Reclosing excluded from being maintained.
Consideration of Comments: Project 2007-17.2
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Question 1 Comment
Response: Thank you for your comments.
1) The standard does not specify how entities execute the maintenance of Protection Systems or Automatic Reclosing
components. The maximum intervals in the Tables for Protection Systems and Automatic Reclosing activities are in
alignment.
2) The SAMS/SPCS report describes the rationale for its recommendations. PRC-005-3 describes the maintenance
requirements for Automatic Reclosing based on those recommendations.
3) The recommendation from the SAMS/SPCS report is based on a reclosing system malfunction for single-contingency
conditions. The condition represented in the comment is a more severe multiple contingency condition.
4) The drafting team believes that the required analysis is sufficient.
5) The recommendation from the SAMS/SPCS report is based on a reclosing system malfunction for single-contingency
conditions. The condition represented in the comment is a more severe multiple contingency condition.
6) Applicability section 4.2.6.2., in accordance with the recommendations from the SAMS/SPCS report, includes the 10 circuit
mile criteria regardless of TP, PC, or BA area boundaries.
7) Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address
conditions where changes in the Balancing Authority Area result in additional locations becoming subject to the
Applicability.
Dominion
No
Dominion agrees with most points and conceptually supports the SDT effort to limit
additional applicability of this to those facilities identified in the Considerations for
Maintenance and Testing of Autoreclosing Schemes report. We are however concerned
that footnote 1 requires the “equipment owner can demonstrate that a close-in threephase fault present for twice the normal clearing time (capturing a minimum trip closetrip time delay) does not result in a total loss of generation in the Interconnection
exceeding the largest unit within the Balancing Authority Area where the Automatic
Reclosing is applied.” We do not believe that most Distribution Providers or Generator
Owners have access to the information, or staff with necessary skills to make such
assessments. In fact, we are not confident that entities with such access and skilled
staff can make such as assertion. At best we believe an entity with the necessary access
and skills could perform an analysis and indicate whether acceptable voltages, flows,
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Question 1 Comment
angles and stability would be adversely impacted by incorrect operation of an
Automatic Reclosing. We do not believe such entity could determine whether or not an
incorrect operation would “....result in a total loss of generation in the Interconnection
exceeding the largest unit within the Balancing Authority Area where the Automatic
Reclosing is applied.”We therefore conceptually support most of the standard but
request the SDT consider adding a requirement that the Transmission Planner provide
a list of those facilities where incorrect operation of Automatic Reclosing has been
shown to result in such loss or alternatively to identify facilities where incorrect
operation could be shown to result in violation of IROLs.
Response: Thank you for your comments.
1) The footnote is an option available to Automatic Reclosing owners for excluding the associated components from a
maintenance program.
2) It is the responsibility of the Transmission Owner, Generator Owner, and Distribution Provider with Automatic Reclosing
to apply the standard and to perform the necessary evaluations to exclude otherwise-applicable Automatic Reclosing from
their PSMP if they desire to do so.
Florida Municipal Power
Agency
No
FMPA is generally supportive of the changes to the standard to accommodate
Reclosing Relays as directed by FERC. We have one comment: The SDT should
recognize that there are a number of small BAs and that the Applicability 4.2.6.1 would
be better stated as the largest generator within the Reliability Coordinator area as
opposed to the largest generator in the Balancing Authority area (e.g., for some BAs,
the largest generator in their area is less than 10 MW and not even registered). If left
unchanged, FMPA would recommend a Negative vote.
Response: Thank you for your comments.
The drafting team revised the applicability to clarify that the applicable locations are where “the total installed gross generating
plant capacity is greater than the gross capacity of the largest BES generating unit within the Balancing Authority Area.”
Hydro One Networks Inc.
No
ï€ We do not agree with Footnote 1 in the standard which places the onus on the
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Question 1 Comment
equipment owner of the reclosing relays to demonstrate which reclosing relays can be
excluded by making the determinations outlined in the footnote. This is clearly the
role of the Reliability Coordinator or Planning Coordinator and not the equipment
owner. Consequently, we believe that the applicability of this standard should be
expanded to RCs and/or PCs in order to properly conduct the sort of studies asked for
in the standard. ï€ Also, the standard assumes that all relays are in scope and entities
have to systematically exclude relays based on the footnote. We don’t agree with this
approach since it is onerous and leaves room for interpretations. We suggest that
standard is changes so that the onus is placed on the RC or PC to identify such relays. ï€
Section 4.2.6.3 is not specific enough in terms of in-scope reclosing used in an SPS. Use
of the word “integral part of an SPS” is subject to interpretation and may require
details of the SPS not readily available to the owner of the reclosing relays. ï€ We
propose that the maintenance for Automatic Reclosing installed on the lines defined at
Section 4.2.1 should be done at the same time with the maintenance of Protection
Systems installed on those lines. If the owner of the two relays is not the same, we
recommend that the standard requires coordination between two entities. Similarly,
the maintenance for Automatic Reclosing used as an integral part of a SPS defined in
Section 4.2.4 should be done at the same time with the maintenance for SPS. The
revision of the standard should only reflect these changes. Please see the rational
below:The report attached as a supporting document mentions as a credible failure “a
close signal is issued with no delay or less delay than is intended”. This failure should
be classified as either a normal contingency or an extreme contingency. The
classification is important because the TPL standards define different study conditions
based on contingency classification. Sections 4.2.6.1 states that Automatic Reclosing
should be maintained “at generating plants substations where the total installed
capacity is greater than the capacity of the largest generating unit within the Balancing
Authority”. However, depending on the assumptions (how the system is stressed,
extreme weather, etc.) and specific configurations, there may be other locations,
where if the double three phase fault described in the Footnote 1 is applied, the total
generation loss could be greater than the largest unit within the Balancing Authorities.
The standard lacks a common methodology for performing the double three phase
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fault described in the Footnote 1: ï€ The standard does not specify the conditions
(extreme weather base case, extreme contingencies base case, how the generators are
dispatched, etc.) or what would be the time delay between the first and second fault.
All these conditions may affect the total generation loss.ï€ The 10 circuit-miles criteria
should be confirmed with the Planning Coordinators.ï€ Depending on the location of
the line being tested, different neighboring entities may be involved.ï€ There should be
a process in place to update the list of the Automatic Reclosing excluded from being
maintained.
Response: Thank you for your comments.
1) It is the responsibility of the Transmission Owner, Generator Owner, and Distribution Provider with Automatic Reclosing
to apply the standard and to perform the necessary evaluations to exclude otherwise-applicable Automatic Reclosing from
their PSMP if they desire to do so.
2) The standard does not specify how entities execute the maintenance of Protection Systems or Automatic Reclosing
components. These can be performed together or separately based on the entity’s processes. The maximum intervals in
the Tables for Protection Systems and Automatic Reclosing activities are in alignment.
3) The SAMS/SPCS report describes the rationale for its recommendations. PRC-005-3 describes the maintenance
requirements for Automatic Reclosing based on those recommendations.
4) The recommendation from the SAMS/SPCS report is based on a reclosing system malfunction for single-contingency
conditions. The condition represented in the comment is a more severe multiple contingency condition.
5) Applicability section 4.2.6.2., in accordance with the recommendations from the SAMS/SPCS report, includes the 10 circuit
mile criteria regardless of TP, PC, or BA area boundaries
6) Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address
conditions where changes in the Balancing Authority Area result in additional locations becoming subject to the
Applicability.
Ingleside Cogeneration LP
No
Ingleside Cogeneration LP is generally supportive of the changes that the drafting team
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(Occidental Chemical
Corporation)
Question 1 Comment
has made to PRC-005-2 and supporting documentation to address FERC Order 758.
First and foremost, we agree that the definition of “Protection System” should not be
modified as it has implications to any standard that uses the term. This far exceeds the
scope of FERC’s directive - which only identifies recloser maintenance as a reliability
imperative. Second, we believe that the underlying technical basis for the
identification of recloser relays that “can affect the reliability” of the BES is sound. The
analysis performed by NERC’s System Analysis and Modeling and System Protection
and Control Subcommittees (SAMS-SPCS) is compelling in our view. In this manner, the
industry and CEAs can focus on those components which may pose risk to the local
system - and not expend resources on those which do nothing to improve electric
service delivery. However, as a Generator Owner, we are not sure how we will capture
the information we need to conduct an analysis of our recloser relays. We can
approach our Balancing Authority to have them provide the “capacity of the largest
generating unit” within their control area - but have no recourse if they refuse to
respond due to security or anti-competitive reasons. Even if this is not an issue, it
seems plausible that an extended outage of the BA’s largest generator may re-set PRC005-3’s applicability threshold downward. If this happens, we may be required to reevaluate our equipment base on a moment’s notice. We don’t believe it is the drafting
team’s intent to establish thresholds which may change in this manner.It would be far
simpler if an Interconnect-wide capacity threshold could be established within PRC005-3. Those Balancing Authorities that require a lower threshold could communicate
their expectations to their base as they see fit.
Response: Thank you for your comments.
1. Thank you for your support.
2. Thank you for your support.
3. Thank you for your support.
4. The drafting team believes that BAs will be willing to share the relevant information; note that this information may not
include the identification of the largest BES generator in the Balancing Authority Area, but only the gross capacity of that
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Question 1 Comment
generator.
5. This is a planning-time-frame horizon standard, and the drafting team believes that extended outages would be addressed
by means of operating changes.
6. It would be inappropriate to establish an interconnection-wide threshold. The drafting team developed a second
implementation plan, “Implementation Plan for Newly identified Automatic Reclosing Components due to generation
changes in the Balancing Authority Area”, in consideration of the scenario you describe.
American Electric Power
No
It is not clear exactly which sort of automatic reclosing behavior(s) the proposed
changes are attempting to prevent. Accidental reclosing? Failure to reclose? Providing
clarity on this fundamental question will help industry in providing sound comments
and feedback regarding PRC-005-3.Does mentioning “interlock circuits” in the second
bullet under Automatic Reclosing (page 2 of redline) refer narrowly to circuitry inside
breaker mechanisms or does it also include lockout strings associated with lockout
relays?
Response: Thank you for your comment.
The report by NERC SAMS and SPCS describes the behavior to be avoided as premature autoreclosing that has the potential to
cause generating unit or plant instability. The drafting team removed the text regarding “interlock circuits” from the definition.
Lincoln Electric System
No
LES is concerned with how components of a reclosing system would be identified if an
automatic line isolation scheme is included within a reclosing scheme. For instance, in
some configurations, if a trip were to occur on a transmission line, one reclose is
performed. If the line immediately trips again (i.e., the fault is not cleared), the line is
automatically isolated with a line switch followed by a second reclose. This is done in
order to pick up the load on a transformer that may be on the same line terminal at the
substation. However, in the event there is a failure of the line switch, the second
reclose is cancelled. In consideration that this would affect reclosing, LES asks that the
drafting team provide further clarification as to whether the components associated
with the line switch operation would be included as part of the PSMP as
well.Additionally, if reclosing is supervised by a sync-check function, whether included
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in the relay performing the reclosing or else in a separate relay, should that relay, and
the voltage inputs needed to do sync-check, be included in the PSMP also? To ensure a
consistent understanding amongst registered entities, LES recommends the drafting
team add clarifying language to Applicability Section 4.2.6 or else provide further
guidance within the Supplementary Reference and FAQ document.
Response: Thank you for your comments.
As noted on page 12 of the SAMS/SPCS report, the concern being addressed within the standard is premature autoreclosing that
has the potential to cause generating unit or plant instability. Therefore, the drafting team believes that, if the reclosing
application addressed falls within the standard, the requirements apply, regardless of any sectionalizing in the vicinity. However,
supervisory capabilities such as sync-check or line switch status are not included.
ReliabilityFirst
No
No, the reclosing relays in the Applicability section were overly restricted. Improper
operation of reclosing relays can exacerbate fault conditions and severely damage
equipment that affects the long term reliability of the Bulk Power System. The
Applicability section limits the facilities concerning automatic reclosing to those
integral to an SPS or substations (and those one bus away) where the total installed
generating plant capacity is greater than the capacity of the largest generating unit
within the Balancing Authority Area. This bar is so high that substations with units as
high as 1200 MVA may not be covered by this revised standard. The capacity limit
should either be removed or reduced to no more than half the largest generating unit
within a BA. Also, the definition of Automatic Reclosing should include supervisory
elements like synchronism check or dead-line check as these can be integral parts of
the reclosing scheme.
Response: Thank you for your comments.
The drafting team requested guidance from the NERC SAMS and SPCS regarding the applicability, as well as suggested maximum
maintenance intervals and minimum maintenance activities. In response to this request, SAMS and SPCS studied various
concerns regarding automatic reclosing, and determined that only those conditions being addressed in the Applicability of PRC005-3 needed to be addressed. The maximum maintenance intervals and minimum maintenance activities for the applicable
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components are described in Table 4.
ISO RTO Council Standards
Review Committee
No
The IRC members compliment the SDT in using the recommendations provided in the
SAMS/SPCS Order 758 Autoreclosing Report for the applicability of this standard
directive to specific reclosing relays. By using these recommendations, Transmission
Owners are provided guidance and reduced burden that should satisfy the Commission
conclusion in the Order that “specific requirements fo selection criteria should be used
to identify reclosing relays that affect the reliability of the Bulk-Power System.” The IRC
members are not directly impacted by the PRC-005 requirements from a compliance
standpoint because we are generally not Transmission Owners. We are raising these
questions to highlight the lack of communications between the stakeholder industry
experts and the regulator directing technical requirements on the industry . As
everyone in the industry knows, seven years’ experience with the ERO has caused
significant burdens on meeting compliance requirements with numerous requirements
being in effect and entities having to significantly increase resources in compliance and
not always justifying whether such expenses are a benefit to the end consumer. NERC
must develop processes and form relationships with the regulators who have these
specific technical concerns to bring their concerns and issues to the industry experts in
a more direct and efficient manner to avoid delays in standards development and
approval and expending more resources in the regulatory process rather through a
technical process. We question whether the approach the SDT has taken to address the
FERC Directive in Order 758 addresses the core reliability concern that the Order seems
to raise. First, the Order states that reclosing relays are not explicitly identified as part
of the “Protection System” and if it plays a part in the “Protection System” to “achieve
or meet system performance requirements” or “can exacerbate fault conditions when
not properly maintained and coordinated” then there could be a gap in the
maintenance and testing of the relays. Second the Order recognizes that certain
parties in comments to the NOPR believe reclosing relays are used not for reliability
reasons but for business purposes in restoration post-contingency. Further
commenters stated that specific call outs for reclosing relays in PRC-005 are not
necessary because reclosing relays are already integral to an entity’s relay maintenance
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program. Nevertheless, FERC has directed NERC to add reclosing relays to the standard
There is no further technical justification for adding reclosing relays to the standards.
The referenced language from the Order can be challenged by a protection system
designer in that a reclosing relay may not be integral to “achieve or meet system
performance requirements” nor “can exacerbate fault conditions” because they may
have been designed to provide onlyrestoration of service for customer satisfaction and
be in a part of the system that cannot exacerbate a fault condition (e.g. tap
configuration). Does a registered entity subject to this requirement have the ability to
demonstrate a particular reclosing relay does not meet the apparent reliability concern
specified in the Order and exclude those reclosing relays from the compliance
program? An all inclusive approach to apply the PRC-005 requirements for all reclosing
relays may have little to no reliability benefit to the grid. In addition, we offer the
following comments for the SDT’s consideration to achieve consistency in the terms
used and the precise devices that the revised standard should apply:a. Definition of
PSMP: the term “Automatic Reclosing” should not be capitalized since it is indicated
that the term is defined for use only within PRC-005-3, and should remain with the
standard upon approval rather than being moved to the Glossary of Terms. With this
term not to be balloted and included in the Glossary, it should be in lower case.b.
Order 758 directed NERC to include “reclosing relays” that can affect the reliable
operation of the Bulk-Power System. Automatic reclosing is an act or intent, not a
device. It is the latter that needs to be maintained and tested for continued
functionality, not the former. Therefore, we suggest that the term “Automatic
Reclosing” be replaced with “reclosing devices” or “reclosing relays” in the revised
PSMP definition, in Sections A.1, A.3 and A.4.2.6, and throughout the standard where
“automatic reclosing” is addressed/referenced.c. We interpret the FERC directive to
require not just the automatic reclosing devices/relays be included in PRC-005, but also
the relays/devices that may be used for manual reclosing. In other words, both
automatic and manual reclosing devices/relays need to be included in the standard. To
enable this applicability, we suggest not removing the word “automatic” where it
appears.
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Question 1 Comment
Response: Thank you for your response. To address your suggestions:
a) The drafting team agrees with you and un-capitalized the term “Automatic Reclosing” within the definition of PSMP.
b) The drafting team considers "reclosing" to be a noun and "automatic" to be an adjective. The term "Reclosing relays" does
not capture the all of the components that need to be maintained to meet the objectives of the standard. The drafting
team requested guidance from the NERC SAMS and SPCS regarding the applicability, as well as suggested maximum
maintenance intervals and minimum maintenance activities. In response to this request, SAMS and SPCS studied various
concerns regarding automatic reclosing, and determined that only those conditions being addressed in the Applicability of
PRC-005-3 needed to be addressed.
c) The drafting team’s use of the terms "reclosing" and “automatic reclosing” are consistent with the use of the terms within
IEEE standards. It is clear from the SAMS - SPCS report that automatic reclosing, not manual reclosing, is the concern that
needs to be addressed by the standard.
Northeast Power Coordinating
Council
No
The maintenance for Automatic Reclosing installed on the lines defined at Section 4.2.1
should be done at the same time with the maintenance of Protection Systems installed
on those lines. Similarly, the maintenance for Automatic Reclosing used as an integral
part of a SPS defined in Section 4.2.4 should be done at the same time as the
maintenance for a SPS. This should be reflected in this revision of the Standard. The
Considerations for Maintenance and Testing of Autoreclosing Schemes report attached
as a supporting document mentions as a credible failure “a close signal is issued with
no delay or less delay than is intended”. This failure should be classified as either a
normal contingency or an extreme contingency. The classification is important because
the TPL standards define different study conditions based on contingency
classifications. How are interconnections to be considered in Applicability Section 4.2.6
Automatic Reclosing? Section 4.2.6.1 states that Automatic Reclosing should be
maintained “at generating plant substations where the total installed capacity is
greater than the capacity of the largest generating unit within the Balancing Authority
Area”. However, depending on the assumptions used for system configurations, there
may be other locations where if the double three phase fault described in Footnote 1 is
applied, the total generation loss could be greater than the largest unit within the
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Question 1 Comment
Balancing Authority. Also, should the criteria be based on largest single source loss
rather than largest generating unit? Otherwise, there is no mechanism that triggers
review of applicability of this standard. For example, what if the largest generating unit
within the BA Area is removed permanently from service? This is applicable in the
Northeast, where TO and GO functions are performed by different entities/owners.
The BA is the entity that determines the largest single source loss in its area; they
would also be the proper functional entity to identify the generator locations in 4.2.6.1.
The TPL or the BAL standards could then include a trigger mechanism to review
applicability of 4.2.6 to GOs and TOs for a change in the largest single source loss
criteria/limit. From a Registration Criteria perspective, the terms “unit” and “plant” as
employed in the Registration Criteria suggest a two-part Applicability test. The first part
is a comparison between the single “largest generating unit” and a larger multi-unit
generating plant located at a single site (i.e., the term a “plant” as used in NERC Rules
of Procedure, Appendix 5B NERC Statement of Compliance Registry Criteria). In this
first part of the test the sum of the capacity ratings of the smaller individual units
exceeds the single “largest generating unit” within the Balancing Authority Area. This is
compared with a single “largest generating unit.” The second part of the Applicability
test relates to the “generating plant substations.” In this phrase the word “substations”
is plural. This plural wording suggests that the multi-unit generating plant feeds more
than one substation. Suggest the following alternatives to the wording of Section
4.2.6.1: “Where generating plant substations are interconnected locally at the
generating plant site, or adjacent to the generating plant site, and applied on BES
Elements at the generating plant substations.” Or”Automatic Reclosing is applicable
where the total site installed generating plant capacity is greater than the capacity of
the largest generating unit within the Balancing Authority Area or when 4.2.6.3
applies.”Applicability Section 4.2.6.2 addresses the electrical and geographical
proximity of the “generating plant substations” interconnections by stating “one bus
away” and “less than 10 circuit-miles from the generating plant substation.” For
clarification, suggest revising Section 4.2.6.2 to read “Where generating plant
substations are interconnected at a distance from the generating plant site, applied on
BES Elements at substations located one bus away from generating plant substations
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Question 1 Comment
when the substation is less than 10 circuit-miles from the generating plant substation.”
What is the technical justification for the 10 circuit-miles? It may be necessary to
confirm the 10 circuit miles with the Planning Coordinator.It is not clear if a substation
“one bus away from generating plants” that meets the criteria in 4.2.6.2 and includes
buses at two voltage levels, separated by a power transformer, is considered as one
bus, or as two buses separated by a power transformer. If the former applies,
reclosing relays on elements at only one of the substation buses would be included in
this standard.If a reclosing relay is found non-functional during maintenance activity
and has to be removed from service for an extended period of time, which in turn fully
removes automatic reclosing functionality, is it still identified as an Unresolved
Maintenance Issue? The final SAMS-SPCS report states that if “No close signal is
issued under conditions that meet the intended design conditions, (...) this failure
mode does not create any additional considerations for inclusion of autoreclosing
relays in PRC-005”, which implies that it would not be identified as an Unresolved
Maintenance Issue. Footnote 1 is not explicit as to the reclosing operation referred to.
The Requirement appears to address only three pole, single shot reclosing. There is no
reference to single pole reclosing or cases where multiple shot reclosing may be
utilized. A more generalized statement should be considered: Automatic Reclosing
addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that, in the event of a close-in permanent fault, the reclosing utilized
does not result in a total loss of generation in the Interconnection exceeding the
largest unit within the Balancing Authority Area where the Automatic Reclosing is
applied.Rationale should be provided to describe the system conditions to be
considered for studying the three phase fault described in Footnote 1. Footnote 1
places the burden on the owner of the reclosing relays to demonstrate which reclosing
relays can be excluded by making the determinations outlined in the footnote. This
should be the role of the Reliability Coordinator or Planning Coordinator and not the
equipment owner. Consequently, we believe that the applicability of this standard
should be expanded to RCs and/or PCs in order to properly conduct the sort of studies
asked for in the standard. Section 4.2.6.3 is not specific enough with regard to
reclosing used in an SPS. The use of the word “integral part of an SPS” is subject to
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interpretation and may require details of the SPS that will not be readily available to
the owner of the reclosing relays. There should be a process in place to update the list
of the Automatic Reclosing excluded from being maintained. The standard must
consider that neighboring entities may be involved in the lines being tested.
Response: Thank you for your comments.
1) The standard does not specify how entities execute the maintenance of Protection Systems or Automatic Reclosing
components. These can be performed together or separately based on the entity’s processes. The maximum intervals in
the Tables for Protection Systems and Automatic Reclosing activities are in alignment.
2) The SAMS/SPCS report describes the rationale for its recommendations. PRC-005-3 describes the maintenance
requirements for Automatic Reclosing based on those recommendations.
3) Applicability section 4.2.6.2., in accordance with the recommendations from the SAMS/SPCS report, includes the 10 circuit
mile criteria regardless of TP, PC, or BA Area boundaries.
4) The recommendation from the SAMS/SPCS report is based on a reclosing system malfunction for single-contingency
conditions. The condition represented in the comment is a more severe multiple contingency condition.
5) Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address
conditions where changes in the Balancing Authority Area result in additional locations becoming subject to the
Applicability.
6) “Plant” and “Unit”, as used in the Applicability are correct and align with the Registry Criteria.
7) Applicability section 4.2.6.2., in accordance with the recommendations from the SAMS/SPCS report, includes the 10 circuit
mile criteria regardless of TP, PC, or BA Area boundaries
8) Individual buses, as described in Applicability section 4.2.6.2, would be separated by BES Elements, whether transformers
or lines.
9) The described condition would be an Unresolved Maintenance Issue if it cannot be completed by the end of the scheduled
maintenance interval.
10) As noted on page 12 of the SAMS/SPCS report, the concern being addressed within the standard is premature
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autoreclosing that has the potential to cause generating unit or plant instability. Therefore, the drafting team believes
that, if the reclosing application addressed falls within the standard, the requirements apply, whether the reclosing is
three-phase or single-phase, or multiple shot or single shot.
11) The recommendation from the SAMS/SPCS report is based on a reclosing system malfunction for single-contingency
conditions. The condition represented in the comment is a more severe multiple contingency condition.
12) Automatic reclosing components that are an “integral part” of a Special Protection System (SPS) would be Automatic
Reclosing that is necessary for the SPS to function properly and provide the outcome intended. If failure or inadvertent
operation of Automatic Reclosing keeps an SPS from performing its intended function, the requirements of PRC-005-3
would apply to that equipment.
13) Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address
conditions where changes in the Balancing Authority Area result in additional locations becoming subject to the
Applicability.
American Transmission
Company
No
The PRC-005 standard is directed at the Transmission Owner (TO), not the
Transmission Planner (TP). The TO may not have the ability to perform the analysis
that is required to identify exclusions and ATC recommends that the SDT address this
issue.
Response: Thank you for your comments.
The footnote is an option available to Automatic Reclosing owners for excluding the associated components from a maintenance
program.
CenterPoint Energy
No
The SAMS/SPCS study of automatic reclosing identifies 1 circuit-mile impedance as
typically adequate to prevent generating unit instability and that 10 circuit-miles
impedance is a sufficient margin. CenterPoint Energy requests that the SDT reevaluate
the technical basis for selecting 10 circuit-miles as “sufficient margin” and
incorporating this distance into the Applicable Facilities section 4.2.6.2. Since the
SAMS/SPCS study states that 1 circuit mile impedance is adequate, it is possible that 5
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circuit-miles or some other distance will provide a sufficient margin.
Response: Thank you for your comments.
In accordance to a request, SAMS and SPCS developed the recommendations within their report. SAMS believes that 10 circuit
miles was an appropriate criterion providing sufficient margin. The SAMS and SPCS groups have the expertise to make that
determination.
SERC Protection and Controls
Subcommittee
No
Under the Facilities Section, the drafting team included Footnote #1 which allows an
exclusion of certain locations that meet the test criteria; however, there is no stated
time frame to re-validate the results of stated test. We recommend that the drafting
team specifies a re-validation period of 60 months.
Response: Thank you for your comments.
Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address conditions
where changes in the Balancing Authority Area result in additional locations becoming subject to the Applicability.
Pepco Holdings Inc & Affiliates
No
We agree with the reasoning behind NERC’s System Analysis and Modeling
Subcommittee (SAMS) recommendation to limit the applicability of automatic reclosing
to only those installations that would impact the reliability of the BES. The three
criteria (Sections 4.2.6.1, 4.6.2.2, and 4.6.2.3) identified in the PRC-005-3 draft and FAQ
document seem reasonable and appropriate. However, additional clarification is
needed to ensure uniform interpretation of these criteria. Consider the following
scenario. Suppose a certain generating plant has 500 MVA of generation
interconnected at a 230kV bus, 300 MVA interconnected at a 138kV bus, and 200 MVA
interconnected at a 69kV bus. There are autotransformers connecting the 138kV bus
to both the 230kV and 69kV busses. 1 ) How is total plant capacity to be calculated?
Is it the sum of all generation capacity at the plant (500 + 300 + 200 = 1000 MVA), even
though it is not all interconnected at the same bus, and some of it is connected below
100kV? Or, should the aggregate generation capacity interconnected on each bus be
Consideration of Comments: Project 2007-17.2
38
Organization
Yes or No
Question 1 Comment
evaluated separately for those lines connected to that bus? Depending on the size of
the autotransformers which interconnect the three busses, the transformer thru
impedance could be comparable to, or exceed, the equivalent impedance of 10 circuit
miles of line. If this were the case, it would seem that evaluation of plant capacity
should be permitted to be calculated on an individual bus basis, rather than a total
plant basis. Also, can the 200 MVA of generation interconnected at the 69kV bus be
excluded from the total plant capacity, since it is interconnected below 100kV, and
therefore not BES generation? Section 4.2.6.1 should be re-worded to provide clarity
and eliminate confusion on how to evaluate this plant capacity calculation. Also,
specific examples illustrating how to apply this criterion would be helpful in the FAQ. 2
) Section 4.2.6.1 states that it applies to “all BES elements at generating plant
substations...”. The transmission line (including both ends) is considered a BES
element. Therefore one might interpret this as applying to both ends of any BES
element that terminates on a generating plant substation. We believe the intent of
4.2.6.1 is to only apply to the automatic reclosing schemes on the line terminals
located at the generating station and to not apply to the automatic reclosing schemes
on the opposite ends of the lines remote from the generating plant substation.
Automatic reclosing schemes on lines terminating on generating stations usually
employ a leader-follower philosophy, with the remote terminal programmed as the
reclose initiate terminal, and the generating station end of the line reclosing only upon
a successful restoration of the far end. A reclosing mal-function at the far terminal
should have no consequences for the generating plant, provided there is no other
electrically short (within 10 circuit miles) transmission path from the far terminal back
to the generating plant. To provide clarity, Section 4.2.6.1 should be re-worded as
follows: “Applied on the terminals of BES Elements located at generating plant
substations...”. For consistency, Section 4.2.6.2 should also be re-worded as follows:
“Applied on the terminals of BES Elements located at substations...”. Also, specific
examples and clarifications in the FAQ would also be helpful. 3 ) For consistency, when
determining plant capacity and capacity of the largest generating unit within the
Balancing Authority Area, rated generator nameplate MVA ratings should be used
rather than published seasonal MW values. 4 ) The NERC SAMS review concluded
Consideration of Comments: Project 2007-17.2
39
Organization
Yes or No
Question 1 Comment
that automatic reclosing mal-performance affects BES reliability when “inadvertent
reclosing near a generating station subjects the generation station to severe fault
stresses”. The concern appears to be potential shaft torque damage, or instability, of
rotating machines to automatic reclosing mal-performance. That being the case,
generation sources that are not subject to severe fault stresses, such as inverter based
generation, or static reactive sources (SVC’s, capacitor banks, etc.) should not be
included in the calculation of total plant capacity. However, since synchronous
condensers are subject to the same fault stresses as synchronous generators they
should probably be included in the aggregate plant generation calculation, providing
they are interconnected at 100kV, or above.
Response: Thank you for your comments:
1. According to NERC Rules of Procedure, Appendix 5B – NERC Statement of Compliance Registry Criteria, “plant” is used to
refer to a multi-unit generating plant located at a single site.
2. The Applicability sections you reference were revised in consideration of your comments.
3. After further discussion, the drafting team determined that gross aggregated plant ratings and gross generator ratings
should be used. The standard was revised accordingly.
4. Footnote 1 covers the condition you reference.
Duke Energy
No
We believe the modifications to the PRC-005-2 Applicability section 4.2.6.1 should
recognize that the reliability issue is inadvertent reclosing, and therefore applicability
on BES Elements at generating plant substations should be limited to the timing and
sync check functions of reclosing. There is no need to include all DC circuitry, etc.
because if a problem existed aside from timing and sync check, it would just prevent
reclosing. Also, rather than being focused only on plant capacity, there should be some
recognition that plant location on the BES is also a consideration. Duke Energy believes
the Applicability section 4.2.6.2 should be based on a technical assessment as
illustrated in the SAMS/SPCS paper. This type of assessment should be based on a
simulation of a close-in-three-phase fault for twice the normal clearing time. This
simulation would capture a minimum trip-close time delay.
Consideration of Comments: Project 2007-17.2
40
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
1. The standard requires verification that Automatic Reclosing, upon initiation, does not issue a premature closing command.
The definition of Automatic Reclosing and the associated maintenance activities in Table 4 were revised for clarity.
2. Footnote 1 allows the entity to exclude generator buses when they do not meet the SAMS recommendation.
exelon and its Affiliates
No
We understand the concerns related to reclosing relays however we do not agree that
these devises should be included in PRC-005 because reclosing relay are not a
protective device. The current system stability studies do not rely on automatic
reclosing to maintain the reliability of the Bulk Power System.
Response: Thank you for your comment.
As you point out reclosing relays are not protective devices. That is the reason these devices were not added to the Protective
System definition. The reclosing relays addressed in this standard are a very narrowly defined set of devices. These devices could
cause plant instability if they failed causing an instantaneous close after trip on a large generation bus. The drafting team is acting
in accordance with the schedule NERC provided to FERC, which outlines the timeframes by which NERC will respond, through the
standards drafting process, to the directives of FERC Order 758. Specifically regarding reclose relays (Footnote 37), FERC directed
NERC to: “By July 30, 2012, NERC should submit to the Commission either the completed project which addresses the remaining
issues consistent with this order, or an informational filing that provides a schedule for how NERC will address such issues in the
Project 2007-17 reinitiated efforts.”
Entergy Services, Inc.
Yes
Entergy agrees with the inclusion of the reclosing relay maintenance requirement
except for how the terminology is addressed. Entergy suggests not adding of the term
Automatic Reclosing; instead add reclosing relay and the associated circuitry
description under Protection System definition.
Response: Thank you for your comment.
The drafting team chose not to add reclosing devices to the definition because they are not protective devices.
Tacoma Power
Yes
Tacoma Power has the following comments regarding improvements to the
Consideration of Comments: Project 2007-17.2
41
Organization
Yes or No
Question 1 Comment
standard:1. *Regarding 4.2.6.1 and 4.2.6.2, there are some generating plants that may
be in a different Balancing Authority area than the Transmission Owner with which
they interconnect. This may complicate the determination of applicability of
Automatic Reclosing under PRC-005-3.2. Regarding 4.2.6.2, would it be necessary to
maintain Automatic Reclosing components per PRC-005-3 on BES Elements “facing” an
applicable generating plant? For example, assume that a 5-circuit-mile long line
connects Generating Plant A with Substation B. Would Automatic Reclosing
components at Substation B on the connecting line need to be maintained per PRC005-3? It seems unlikely that a failure of the Automatic Reclosing in this scenario
would have adverse reliability impact to the BES. Of course, this assumes that there is
not another generating plant within 10 circuit miles connected to Substation B. 3.
Consider a substation located within 10 circuit miles of two or more generating plants,
none of which individually applies under 4.2.6.1. Furthermore, assume that these
generating plants collectively have a total installed generating plant capacity greater
than the capacity of the largest generating unit within the Balancing Authority area?
Would the substation apply to 4.2.6.2? 4. In 4.2.6.2, only Automatic Reclosing applied
on BES Elements is applicable. What if there is a non-BES radial line connected to the
substation? It seems that the reliability impact of improper Automatic Reclosing on
this non-BES Element could be as high as that for improper Automatic Reclosing on a
BES Element connected to the substation.
Response: Thank you for your comments:
1. Applicability section 4.2.6.2., in accordance with the recommendations from the SAMS/SPCS report, includes the 10 circuit
mile criteria regardless of TP, PC, or BA Area boundaries.
2. Applicability sections 4.2.6.1 and 4.2.6.2 were revised based on your comments.
3. No, the scenario you describe does not meet the Applicability criteria.
4. Applicability sections 4.2.6.1 and 4.2.6.2 were revised for clarity.
MRO NERC Standards Review
Forum
Yes
The NSRF supports the draft standard PRC-005-3 addressing automatic reclosing as
correct and appropriate.
Consideration of Comments: Project 2007-17.2
42
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
Southern Company - Southern
Company Services, Inc.;
Alabama Power
Company;Georgia Power
Company; Mississippi Power
Company; Gulf Power
Company; Southern Company
Generation; Southern
Company Generation and
Energy Marketing
Yes
Under the Facilities Section, the drafting team included Footnote #1 which allows an
exclusion of certain locations that meet the test criteria; however, there is no stated
time frame to re-validate the results of stated test. We recommend that the drafting
team specifies a re-validation period.
Response: Thank you for your comments.
Entities are expected to be in compliance at all times following the implementation period, and should have current
documentation supporting their compliance. An additional Implementation Plan has been developed to address conditions
where changes in the Balancing Authority Area result in additional locations becoming subject to the Applicability.
SPP Standards Review Group
Yes
Would misoperations of automatic reclosing relays as specified in 4.2.6 have to be
reported in PRC-004-2?
Response: Thank you for your comments.
The drafting team chose not to add reclosing devices to the definition of Protection System because they are not protective
devices. As such, PRC-004-2 would not be affected.
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Consideration of Comments: Project 2007-17.2
43
Organization
Yes or No
Vandolah Power Company
Yes
Self
Yes
OPG
Yes
Idaho Power Company
Yes
Consideration of Comments: Project 2007-17.2
Question 1 Comment
44
2. The drafting team developed an Implementation Plan for PRC-005-3 based on the Implementation Plan for PRC-005-2 to address
the addition of Automatic Reclosing. Do you agree with the implementation plan regarding Automatic Reclosing? If not, please
provide specific suggestions for improvement.
Summary Consideration:
Many commenters agreed with the Implementation Plan.
A few commenters questioned the complexity of the Implementation Plan for PRC-005-3 which includes the Protection System
aspects of PRC-005-2 and adds the new aspects of Automatic Reclosing from PRC-005-3. The plan addresses the implementation of
the PRC-005-2 requirements based on the approval date of PRC-005-2 and adds the implementation of the revised requirements that
include Automatic Reclosing based on the approval date of PRC-005-3. This approach provides clarity regarding the implementation
dates for maintenance of Protection System and Automatic Reclosing Components. The drafting team crafted the Implementation
Plan with guidance from NERC legal staff and believes the Implementation Plan is clear once carefully reviewed.
Several commenters had concerns related to applicable facilities changing because of generation changes within the Balancing
Authority Area. The drafting team developed a second Implementation Plan to alleviate these concerns. The document titled:
“Implementation Plan for Newly identified Automatic Reclosing Components due to generation changes in the Balancing Authority
Area”, is posted with the draft standard.
Organization
ACES Standards Collaborators
Yes or No
No
Question 2 Comment
(1) The SDT needs to clarify the implementation plan. The document is confusing
because it focuses on the PRC-005-2 standard, which is not yet FERC-approved. As a
result, this implementation plan is a moving target. Why not wait until PRC-005-2 gets
approved before initiating another project for the same standard? This would reduce
some of the timing issues and confusion.(2) Why is the drafting team revising a
standard that has not been approved by the Commission yet? The second version was
only filed in February 2013, and the timing of this project is premature. It is quite
possible that the Commission could remand or direct revisions to parts of the standard
and issue other directives associated with the version 2, which would then need to be
Organization
Yes or No
Question 2 Comment
addressed. This project is untimely and should be postponed until there is a final order
from FERC. At that point, there may be justification to continue with this project,
expand the scope of the SAR to address any new directives that may be included in a
final order of PRC-005-2, or to determine that a guidance document is an appropriate
way to satisfy the FERC orders.(3) Again, the drafting team needs to consider other
methods of answering FERC directives. Not every directive needs to be addressed by
developing or revising a standard. Adding reclosing relays to PRC-005 only complicates
the most-violated non-CIP standard. There is enough concern about this standard
already and the drafting team should consider alternative means to address the
reclosing relay issue besides a standard revision.(4) This project contains similar timing
issues as CIP version 4 and CIP version 5 because it is being developed prior to FERC
issuing a final order on the previous version of the standard. The timing is problematic;
registered entities will be forced to constantly be focusing on the next standard. The
implementation plan should provide additional time, similar to PRC-005-2’s two
intervals, to allow registered entities enough time to adjust their PSMT programs for
Protection Systems, and then have additional time to adjust their PSMT plan and
implement auto-reclosing relays.(5) Thank you for the opportunity to comment.
Response: Thank you for your comments.
1. The drafting team crafted the Implementation Plan with guidance from NERC legal staff. The Implementation Plan
addresses the implementation of PRC-005-2 requirements based on the approval dates of PRC-005-2 and adds
implementation of PRC-005-3 requirements based on its approval date. The drafting team believes the Implementation
Plan is clear once carefully reviewed.
2. The drafting team disagrees with the assertion that the timing of this project is premature. The drafting team is complying
with the NERC schedule provided to FERC describing how NERC will address the directives issued in Order No.758.
3. NERC, as well as other entities, provided comments in response to FERC NOPR discussions regarding requirements related
to maintenance of automatic reclosing, essentially proposing equally-effective options. FERC, in response, directed that
NERC specifically include requirements related to maintenance of automatic reclosing within PRC-005.
4. The drafting team does not believe the standards developed for PRC-005 are similar to the CIP versions 4 and 5 in that
Consideration of Comments: Project 2007-17.2
46
Organization
Yes or No
Question 2 Comment
PRC-005-3 simply adds maintenance requirements for Automatic Reclosing Components and does not change the existing
maintenance requirements for the Protection System Components covered in PRC-005-2. The Implementation Plan for
PRC-005-3 does provide the additional time for implementing the changes associated with PRC-005-3.
5. Thank you for providing comments.
Manitoba Hydro
No
(23) General - use the acronyms for “Protection System Maintenance Program”, PSMP
and for “Board of Trustees”, BOT. Both terms are referenced multiple times within the
Implementation Plan document.
Response: Thank you for your comment.
The use of acronyms is optional. The drafting team chose not to in the instances cited.
exelon and its Affiliates
No
1. 4.2.6.1 - How would a PRC-005-3 relay engineer determine or be made aware of “the
capacity of the largest generating unit within the Balancing Authority Area” at any
given moment in time? (e.g., suppose a large Nuclear unit that historically constituted
the largest unit in a given BAA gets retired? This could present an unintentional
compliance trap for the PRC-005-3 owner, unless this information is routinely updated
and published as part of another NERC Standard, or by some other mechanism wherein
the relay engineer could keep abreast of such changes in a timely manner). 2. 4.2.6.1 More clarity is needed on exactly what is meant by “generating plant substations”,
since this collective phrase is not defined in NERC’s most recent Glossary of Terms,
dated 05apr13. BGE example: Wagner Unit #4 Sync Breaker is physically located at
Wagner Power Plant, but because the step-up voltage is 230kV, the output feeds into
Brandon Shores 230kV substation, rather than the local 110kV substation where the
other Wagner machines feed into. In this case, would Brandon Shores be considered
the “generating plant substation” for Wagner Unit #4? 3. 4.2.6.2 - The stated
inclusion criteria “one bus away from generating plants specified in Section 4.2.6.1”
introduces further interpretation difficulty when considering other common generating
configurations, such as: 1. The sync breaker is on the low voltage side of the GSU
transformer and the GSU high side leads constitute a “short” transmission line
Consideration of Comments: Project 2007-17.2
47
Organization
Yes or No
Question 2 Comment
between the Plant (GO) and Substation (TO)2. Same as above but the sync breaker is
located on the high side of the GSU and connects to the TO switchyard by the “short”
transmission line.3. The sync breakers owned by the TO are located in the substation
and connected to the high side of the GSU but operated by the GO, again at the other
end of s short transmission line GO. ( A legacy arrangement that results from the
disintegration of formerly vertically integrated utilities)4. Sync breaker on the high side
of the GSU at the plant, but there is a “long” transmission line connecting the sync
breaker to a TO substation.
Response: Thank you for your comments.
1. The Balancing Authority would have this information and would be able to provide it to entities. Each entity is responsible
for disseminating the information within its own organization. Entities are expected to be in compliance at all times
following the implementation period, and should have current documentation supporting their compliance. An additional
Implementation Plan was developed to address conditions where changes in the Balancing Authority Area result in
additional locations becoming subject to the Applicability. The drafting team developed a second Implementation Plan to
alleviate these concerns. The document titled: “Implementation Plan for Newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area”, is posted with the draft standard.
2. According to the NERC Rules of Procedure, Appendix 5B – NERC Statement of Compliance Registry Criteria, “plant” is used
to refer to a multi-unit generating plant located at a single site.
3. This comment is not related to the question posed on the Implementation Plan. However, the drafting team revised the
Applicability clauses 4.2.6.1.and 4.2.6.2 of PRC-005-3 in consideration of your comments.
Self
No
It will take longer than the team suggests. Suggest a survey to determine a date the
industry can adhere to, if a survey has not been performed yet.
Response: Thank you for your comment.
The drafting team believes the Implementation Plan is sufficient.
ReliabilityFirst
No
No, the implementation plan has an excessively long phased in approach that stretches
Consideration of Comments: Project 2007-17.2
48
Organization
Yes or No
Question 2 Comment
out to 13 years after regulatory approval or 14 years after NERC Board of Trustees
adoption
Response: Thank you for your comment
The drafting team believes the Implementation Plan is sufficient.
Dominion
No
The implementation plan should utilize Transmission Planner (TP) notification to
applicable entities rather than simply base the plan on the regulatory approval date to
start the implementation timelines. This would allow the notified entities to have the
same amount of time that is currently in the implementation plan upon notification
from the Transmission Planner.
Response: Thank you for your comment.
The drafting team believes the Implementation Plan is sufficient.
Nebraska Public Power District No
To implement, it would cause us to have to verify that the reclose actually works as
part of the functional trip check. Otherwise, we have the breakers and relays already
classified as NERC.
Response: Thank you for your comment.
The drafting team revised the maintenance activities within Table 4 in consideration of yours and others concerns.
American Electric Power
No
We are concerned by the second bullet in the General Considerations section where it
states” Whether each component has last been maintained according to
PRC―005―2 (or the combined successor standard PRC―005―3),
PRC―005―1b, PRC―008―0, PRC―011―0, PRC―017―0, or a
combination thereof.” This section implies obligations which reference standards
outside of PRC-005-3 and including a standard which is not yet fully approved (PRC005-02), essentially serving as Measures outside of the proposed standard. In addition,
obligations have no place in an implementation plan if they are not also specified
Consideration of Comments: Project 2007-17.2
49
Organization
Yes or No
Question 2 Comment
within the standard itself. This overall approach sets a bad precedent for the standards
development process.AEP does not recommend basing an implementation date on a
standard which has not been fully approved, as that could prove problematic if in this
case PRC-005-2 fails to become fully approved by FERC but PRC-005-3 *is* approved.
Ideally, we recommend that the implementation date be solely based on PRC-005-3.
However, should the drafting team still wish to include PRC-005-2 in the
implementation plan, perhaps it could instead state that “Unimplemented Protection
System Component maintenance activities per PRC-005-2 will continue to be
implemented in accordance with the PRC-005-2 implementation plan. In addition, the
following Automatic Reclosing Component maintenance activities will be implemented
as part of PRC-005-3...”
Response: Thank you for your comments.
The drafting team crafted the Implementation Plan with guidance from NERC legal staff. The Implementation Plan addresses the
implementation of PRC-005-2 requirements based on the approval dates of PRC-005-2 and adds implementation of PRC-005-3
requirements based on its approval date. The drafting team believes the Implementation Plan is clear once carefully reviewed.
Entergy Services, Inc.
Yes
Entergy agrees with the addition of table 4 except for the terminology Automatic
Reclosing.
Response: Thank you for your comment.
FERC directives from Order 758 instruct NERC to address “reclosing relays” within the reliability standards. In response to the
technical report prepared by NERC SAMS and NERC SPCS, the drafting team developed the term, “Automatic Reclosing” to refer
to the control circuitry associated with reclosing relays as well as the reclosing relays proper, and used this term throughout the
modified standard and Implementation Plan.
FirstEnergy
Yes
FE agrees with the proposed Implementation Plan for V3.
Response: Thank you for your comment and support.
Consideration of Comments: Project 2007-17.2
50
Organization
Yes or No
ISO RTO Council Standards
Review Committee
Yes
Question 2 Comment
We agree with the proposed implementation plan, but suggest that the term
“Automatic Reclosing” with “reclosing devices” or “reclosing relays” be applied
throughout the Implementation Plan document (see out comments under Q1, above).
Response: Thank you for your comment and support.
FERC directives from Order 758 instruct NERC to address “reclosing relays” within the reliability standards. In response to the
technical report prepared by NERC SAMS and NERC SPCS, the drafting team developed the term, “Automatic Reclosing” to refer
to the control circuitry associated with reclosing relays as well as the reclosing relays proper, and used this term throughout the
modified standard and Implementation Plan.
SPP Standards Review Group
Yes
Pepco Holdings Inc & Affiliates
Yes
SERC Protection and Controls
Subcommittee
Yes
MRO NERC Standards Review
Forum
Yes
Northeast Power Coordinating
Council
Yes
Hydro One Networks Inc.
Yes
PPL Corporation NERC
Registered Affiliates
Yes
Duke Energy
Yes
Florida Municipal Power
Yes
Consideration of Comments: Project 2007-17.2
51
Organization
Yes or No
Question 2 Comment
Agency
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Southern Company - Southern
Company Services, Inc.;
Alabama Power
Company;Georgia Power
Company; Mississippi Power
Company; Gulf Power
Company; Southern Company
Generation; Southern
Company Generation and
Energy Marketing
Yes
OPG
Yes
Ingleside Cogeneration LP
(Occidental Chemical
Corporation)
Yes
Ameren
Yes
Tacoma Power
Yes
Lincoln Electric System
Yes
CenterPoint Energy
Yes
Consideration of Comments: Project 2007-17.2
52
Organization
Yes or No
City of Tallahassee
Yes
Independent Electricity
System Operator
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
Question 2 Comment
END OF REPORT
Consideration of Comments: Project 2007-17.2
53
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from July 10, 2013 through
August 23, 2013.
Description of Current Draft:
This is the second draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions
1. Post for a concurrent 45-day comment and ballot
July 2013
2. Conduct recirculation ballot
October 2013
3. BOT Adoption
November 2013
Draft 2: July, 2013
Anticipated Date
1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, the following defined term will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and automatic reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Includes the following Components:
• Reclosing relay
• Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 2: July, 2013
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Draft 2: July, 2013
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
Draft 2: July, 2013
4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System shall be included in a time-based
program as described in Table 1-4
and Table 3.
Component – A component is any individual
discrete
piece of equipment included in a
1.2. Include the applicable monitored
Protection
System or in Automatic Reclosing,
Component attributes applied to each
including
but
not limited to a protective relay,
Protection System and Automatic
reclosing relay, or current sensing device.
Reclosing Component Type
The designation of what constitutes a control
consistent with the maintenance
circuit component is very dependent upon how
intervals specified in Tables 1-1
an entity performs and tracks the testing of the
through 1-5, Table 2, Table 3, and
control circuitry. Some entities test their
Table 4-1 through 4-2 where
control circuits on a breaker basis whereas
monitoring is used to extend the
others test their circuitry on a local zone of
maintenance intervals beyond those
protection basis. Thus, entities are allowed
specified for unmonitored Protection
the latitude to designate their own definitions
System and Automatic Reclosing
of control circuit components. Another
Components.
example of where the entity has some
R2. Each Transmission Owner, Generator
discretion on determining what constitutes a
Owner, and Distribution Provider that uses
single component is the voltage and current
performance-based maintenance intervals in
sensing devices, where the entity may choose
its PSMP shall follow the procedure
either to designate a full three-phase set of
established in PRC-005 Attachment A to
such devices or a single device as a single
establish and maintain its performancecomponent.
based intervals. [Violation Risk Factor:
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5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
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6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
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7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
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9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
Component Type in accordance
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
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10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
their performance-based PSMP.
with their performance-based
PSMP.
their performance-based PSMP.
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Draft 2: July, 2013
11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
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12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to include Automatic Reclosing in
maintenance programs
Project 2007-17.2
Revision to address the
FERC directive in Order
No.758 regarding
Automatic Reclosing
3
Draft 2: July, 2013
TBD
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
• Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
Verify:
• Internal self-diagnosis and alarming (see Table 2).
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
• Alarming for power supply failure (see Table 2).
12 Calendar
Years
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 2: July, 2013
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
• Alarming for change of settings (See Table 2).
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15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
6 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
• Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
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16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 2: July, 2013
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
• Station dc supply voltage
4 Calendar Months
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
18 Calendar
Months
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Draft 2: July, 2013
18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Draft 2: July, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
18 Calendar
Months
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Draft 2: July, 2013
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 2: July, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
• Station dc supply voltage
4 Calendar Months
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
• Float voltage of battery charger
• Battery continuity
18 Calendar
Months
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
6 Calendar Years
Draft 2: July, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
• Station dc supply voltage
Inspect:
• For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 2: July, 2013
Verify that the dc supply can perform as manufactured when ac power is
not present.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Draft 2: July, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Draft 2: July, 2013
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Unmonitored control circuitry associated with SPS.
Draft 2: July, 2013
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 2: July, 2013
No periodic
maintenance
specified
None.
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
• Test and, if necessary calibrate.
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
• Internal self diagnosis and alarming (See Table 2).
• Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
12 Calendar
Years
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Alarming for change of settings (See Table 2).
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28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
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29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
• Internal self diagnosis and alarming (See Table 2).
• Alarming for power supply failure (See Table 2).
Draft 2: July, 2013
12 Calendar
Years
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
30
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
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31
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
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32
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment, with a minimum Segment
population of 60 Components.
Segment – Components of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least sixty
(60) individual Components.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 until results of
maintenance activities for the Segment are available for a minimum of 30 individual
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System Component
or Automatic Reclosing configuration or
application errors are not included in Countable
Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4% of the Components within the Segment, for the
greater of either the last 30 Components maintained or all Components maintained in the
previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
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33
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
Draft 2: July, 2013
34
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from June 28July 10, 2013
through August 1223, 2013.
Description of Current Draft:
This is the firstsecond draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions
1. Post for 30-day formal comment
Anticipated Date
April 2013
2.1. Post for a concurrent 45-day comment and initial ballot
Julyne 2013
3.2. Conduct recirculation ballot
AugustOctober 2013
3. BOT Adoption
November 2013
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1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, thesethe following defined terms will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and Automatic automatic Reclosing
reclosing components are kept in working order and proper operation of malfunctioning components is
restored. A maintenance program for a specific component includes one or more of the following
activities:
•
•
•
•
•
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Includes the following Components:
• Reclosing relay
• Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti‐pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual
componentsComponents.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
Draft 1: April2: July, 2013
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Draft 1: April2: July, 2013
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 AppliedAutomatic Reclosing applied on BES the terminals of Elements
connected to the BES bus located at generating plant substations where the
total installed gross generating plant capacity is greater than the gross
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
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4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
capacity of the largest BES generating unit within the Balancing Authority
Area.
Component Type – Either any one
4.2.6.2 Applied onAutomatic
of the five specific elements of the
Reclosing applied on the
Protection System definition or any
terminals of all BES Elements
one of the two specific elements of
at substations one bus away
the Automatic Reclosing definition.
from generating plants
specified in Section 4.2.6.1 when the substation is less than 10 circuit-miles
from the generating plant substation.
4.2.6.3 AppliedAutomatic Reclosing applied as an integral part of an SPS specified
in Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is
used to address each Protection
System and Automatic Reclosing
Component Type. All batteries
associated with the station dc supply
Component Type of a Protection
System shall be included in a timebased program as described in Table
1-4 and Table 3.
1.2. Include the applicable monitored
Component attributes applied to each
Protection System Component Type
and Automatic Reclosing
ComponentsComponent Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System and Automatic Reclosing
Components.
Draft 1: April2: July, 2013
Component – A component is any individual
discrete piece of equipment included in a
Protection System or in Automatic Reclosing,
including but not limited to a protective relay,
reclosing relay, or current sensing device.
The designation of what constitutes a control
circuit component is very dependent upon how
an entity performs and tracks the testing of the
control circuitry. Some entities test their
control circuits on a breaker basis whereas
others test their circuitry on a local zone of
protection basis. Thus, entities are allowed
the latitude to designate their own definitions
of control circuit components. Another
example of where the entity has some
discretion on determining what constitutes a
single component is the voltage and current
sensing devices, where the entity may choose
either to designate a full three-phase set of
such devices or a single device as a single
component.
5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes time-
R4.
based maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and
Unresolved Maintenance Issue – A
maximum maintenance intervals prescribed
deficiency identified during a maintenance
within Tables 1-1 through 1-5, Table 2, Table
activity that causes the component to not
3, and Table 4-1 through 4-2. [Violation Risk
meet the intended performance, cannot be
Factor: High] [Time Horizon: Operations
corrected during the maintenance interval,
Planning]
and requires follow-up corrective action.
Each Transmission Owner, Generator Owner,
and Distribution Provider that utilizes performance-based maintenance program(s) in
accordance with Requirement R2 shall implement and follow its PSMP for its Protection
System and Automatic Reclosing Components that are included within the performance-based
program(s). [Violation Risk Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct identified Unresolved Maintenance Issues. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning]
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6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4.-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
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7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
3) Maintained a Segment with
Draft 1: April2: July, 2013
9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4.-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4.-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4.-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
Component Type in accordance
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
Component Type in accordance with
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
Draft 1: April2: July, 2013
10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
their performance-based PSMP.
with their performance-based
PSMP.
their performance-based PSMP.
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Draft 1: April2: July, 2013
11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
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12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Complete revision, absorbing maintenance
requirements from PRC-005-1b, PRC-0080, PRC-011-0, PRC-017-0Adopted by
Board of Trustees
Complete revisionProject
2007-17 - Complete
revision, absorbing
maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
RevisionRevised to include Automatic
Reclosing into existing Version
Inclusion ofProject 200717.2 Revision to address
the FERC directive in
Order No.758 regarding
Automatic Reclosing
only
3
TBD
in maintenance programs
Draft 1: April2: July, 2013
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
• Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
• Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
Verify:
• Internal self-diagnosis and alarming (see Table 2).
• Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
• Alarming for power supply failure (see Table 2).
12 Calendar
Years
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 1: April2: July, 2013
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
• Alarming for change of settings (See Table 2).
Draft 1: April2: July, 2013
15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
6 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
• Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Draft 1: April2: July, 2013
16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 1: April2: July, 2013
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
• Station dc supply voltage
4 Calendar Months
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
• Float voltage of battery charger
• Battery continuity
• Battery terminal connection resistance
18 Calendar
Months
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
• Physical condition of battery rack
Draft 1: April2: July, 2013
18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Draft 1: April2: July, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
• Station dc supply voltage
Inspect:
• For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
• Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
• Float voltage of battery charger
18 Calendar
Months
• Battery continuity
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Physical condition of battery rack
Draft 1: April2: July, 2013
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 1: April2: July, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
• Station dc supply voltage
4 Calendar Months
Inspect:
• Electrolyte level
• For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
• Float voltage of battery charger
• Battery continuity
18 Calendar
Months
• Battery terminal connection resistance
• Battery intercell or unit-to-unit connection resistance
Inspect:
• Cell condition of all individual battery cells.
• Physical condition of battery rack
6 Calendar Years
Draft 1: April2: July, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
• Station dc supply voltage
Inspect:
• For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 1: April2: July, 2013
Verify that the dc supply can perform as manufactured when ac power is
not present.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Draft 1: April2: July, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Draft 1: April2: July, 2013
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Unmonitored control circuitry associated with SPS.
Draft 1: April2: July, 2013
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 1: April2: July, 2013
No periodic
maintenance
specified
None.
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
• Test and, if necessary calibrate.
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
• Internal self diagnosis and alarming (See Table 2).
• Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
12 Calendar
Years
• Settings are as specified.
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
• Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
• Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
• Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
Alarming for change of settings (See Table 2).
Draft 1: April2: July, 2013
28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
Draft 1: April2: July, 2013
29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
• Test and, if necessary calibrate
For microprocessor relays:
• Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
• Internal self diagnosis and alarming (See Table 2).
12 Calendar
Years
• Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
• Alarming for power supply failure (See Table 2).
Unmonitored Control circuitry associated with Automatic Reclosing
including the close coil.
Control circuitry associated with Automatic Reclosing including the close coil
whose integrity is monitored and alarmed (See Table 2).
Draft 1: April2: July, 2013
• Settings are as specified.
12 Calendar Years
No periodic
maintenance
specified
Verify the Automatic Reclosing control path including the
close coil.
None.
30
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
Draft 1: April2: July, 2013
31
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
Draft 1: April2: July, 2013
32
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of
Components included in each designated
Segment, with a minimum Segment
population of 60 Components.
Segment – Components of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least sixty
(60) individual cComponents.
2. Maintain the Components in each
Segment according to the time-based
maximum allowable intervals established
in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 until results of
maintenance activities for the Segment are available for a minimum of 30 individual
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment to
determine the overall performance of the
Segment and develop maintenance
intervals.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System Component
or Automatic Reclosing configuration or
application errors are not included in Countable
Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than 4% of the Components within the Segment, for the
greater of either the last 30 Components maintained or all Components maintained in the
previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
Draft 1: April2: July, 2013
33
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
Draft 1: April2: July, 2013
34
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC-005-3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC-005-2 – Protection System Maintenance
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3. According to the combined implementation plan in
this document, entities must develop their revised Protection System Maintenance Program within
twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter twenty-four
(24) months following NERC Board of Trustees adoption of PRC-005-2. This anticipates that it will
take approximately twelve (12) months to achieve regulatory approvals following the November
2012 adoption of PRC-005-2 by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2, or the combined successor standard PRC-005-3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according toPRC-005-2 (or the combined
successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, PRC-017-0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC-005-3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
2
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall remain active throughout the
phased implementation period of PRC-005-3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC-005-3. Standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty-six (156) months following applicable regulatory approval of
PRC-005-2, or in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty-eight (168) months
following the November 2012 NERC Board of Trustees adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of first calendar quarter, twelve (12) calendar months following applicable regulatory approval of
PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty-four (24) months following the
November 2012 NERC Board of Trustees adoption of PRC-005-2, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty-four (24) months following
NERC Board of Trustees adoption of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
3
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
The entity shall be 100% compliant on the first day of the first calendar quarter thirty-six (36)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
3.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twentyfour (24) months following applicable regulatory approval of PRC-005-2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
November 2012 NERC Board of Trustees adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty-eight (48)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
4.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
4
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following the November 2012
NERC Board of Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following NERC Board of Trustees
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
5
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees adoption
of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
6
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
Protection System and Automatic Reclosing Maintenance
Implementation Plan
June, 2013
7
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC-005-3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC-005-2 – Protection System Maintenance
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3. According to the combined implementation plan in
this document, entities must develop their revised Protection System Maintenance Program within
twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter twenty-four
(24) months following NERC Board of Trustees adoption of PRC-005-2. This anticipates that it will
take approximately twelve (12) months to achieve regulatory approvals following the November
2012 adoption of PRC-005-2 by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2, or the combined successor standard PRC-005-3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according toPRC-005-2 (or the combined
successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, PRC-017-0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC-005-3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
2
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall remain active throughout the
phased implementation period of PRC-005-3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC-005-3. Standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty-six (156) months following applicable regulatory approval of
PRC-005-2, or in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty-eight (168) months
following the November 2012 NERC Board of Trustees adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of first calendar quarter, twelve (12) calendar months following applicable regulatory approval of
PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty-four (24) months following the
November 2012 NERC Board of Trustees adoption of PRC-005-2, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first calendar quarter
twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those jurisdictions where no
regulatory approval is required, on the first day of the first calendar quarter twenty-four (24) months following
NERC Board of Trustees adoption of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
3
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
3.
4.
The entity shall be 100% compliant on the first day of the first calendar quarter thirty-six (36)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twentyfour (24) months following applicable regulatory approval of PRC-005-2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
November 2012 NERC Board of Trustees adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty-eight (48)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
4
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following the November 2012
NERC Board of Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following the November 2012 NERC Board of Trustees adoption of PRC-005-2or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following NERC Board of Trustees
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
5
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees adoption
of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
6
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
Protection System and Automatic Reclosing Maintenance
Implementation Plan
AprilJune, 2013
7
Implementation Plan for Newly identified
Automatic Reclosing Components due to
generation changes in the Balancing Authority
Area
Project 2007-17.2 Protection System Maintenance and Testing - Phase 2
(Reclosing Relays)
This applies to PRC-005-3 and successor standards.
Additional applicable Automatic Reclosing Components may be identified because of the addition or
retirement of generating units; or increases of gross generation capacity of individual generating units or
plants within the Balancing Authority area.
In such cases, the responsible entities must complete the maintenance activities, described in Table 4, for
the newly identified Automatic Reclosing Components prior to the end of the following calendar year
unless documented prior maintenance fulfilling the requirements of Table 4 is available.
Unofficial Comment Form
Project 2007-17.2 Protection System Maintenance and
Testing - Phase 2 (Reclosing Relays)
2nd Draft of PRC-005-3
Please DO NOT use this form to submit comments. Please use the electronic form to submit comments
on the 2nd draft of reliability standard PRC-005-3 — Protection System and Automatic Reclosing
Maintenance. Comments must be submitted by 8:00 p.m. Eastern Friday, August 23, 2013. If you have
questions please contact Al McMeekin or by telephone at 803-530-1963.
The project page may be accessed by clicking here.
Background Information:
On February 3, 2012, the Federal Energy Regulatory Commission (FERC) issued Order No. 758 approving
an interpretation of NERC Reliability Standard PRC‐005‐1, Transmission and Generation Protection
System Maintenance and Testing. In addition to approving the interpretation, the Commission directed
that concerns identified in the preceding Notice of Proposed Rulemaking (NOPR) be addressed within
the reinitiated PRC‐005 revisions. The concerns raised in the NOPR pertain to automatic reclosing
(autoreclosing) relays that are either “used in coordination with a Protection System to achieve or meet
system performance requirements established in other Commission‐approved Reliability Standards, or
can exacerbate fault conditions when not properly maintained and coordinated,” in which case
“excluding the maintenance and testing of these reclosing relays will result in a gap in the maintenance
and testing of relays affecting the reliability of the Bulk‐Power System.” To address these concerns, the
Commission concludes that “specific requirements or selection criteria should be used to identify
reclosing relays that affect the reliability of the Bulk‐Power System.”
In response to Order No. 758, the Protection System Maintenance and Testing Standard Drafting Team
(SDT) drafted a Standard Authorization Request (SAR) to modify PRC-005 to include the maintenance
and testing of reclosing relays that can affect the reliable operation of the Bulk-Power System. On May
10, 2012, the NERC Standards Committee (SC) accepted the SAR and authorized that it be posted for
information only along with the 3rd draft of PRC-005-2. The NERC SC noted that PRC-005-2 was in the
final stages of the development process, having passed a successive ballot with 79 percent approval on
June 27, 2012 and was scheduled to be presented for approval at the November NERC Board of
Trustees meeting. Consequently, in recognition of the consensus achieved, the NERC SC determined
that the drafting team should complete the development of PRC-005-2 and immediately thereafter
begin work on PRC-005-3 which would reflect the necessary revisions to address reclosing relays.
The SDT also requested the NERC Planning Committee (PC) provide the technical input necessary to
develop the appropriate revisions to PRC-005. The NERC PC instructed the NERC System Analysis and
Modeling Subcommittee (SAMS) and System Protection and Control Subcommittee (SPCS) to jointly
perform a technical study to determine which reclosing relays should be addressed within PRC-005 and
provide advice regarding the appropriate maintenance intervals and activities for those relays. The final
report was approved by the NERC Planning Committee on November 14, 2012 and provided to the SDT
for guidance in developing PRC-005-3.
In Order No. 758, the Commission also directed NERC to file, by July 30, 2012, either a completed
project, or an informational filing providing “a schedule for how NERC will address such issues in the
Project 2007-17 reinitiated efforts.” On July 30, 2012, NERC submitted an informational filing in
compliance with Order No. 758 with a proposed schedule for addressing reclosing relays. The project
number and name is as follows: Project 2007-17.2 Protection System Maintenance and Testing - Phase
2 (Reclosing Relays)
On January 17, 2013, the NERC SC authorized the draft SAR be posted for formal industry comment
concurrent with project development. The SAR as well as the first draft of PRC-005-3 was posted for a
30-day comment period from April 5, 2013 through May 6, 2013. The PSMT SDT has responded to the
comments from the initial posting and incorporated pertinent suggestions into the second draft of the
standard.
Draft 2 of PRC-005-3 is posted for a 45-day formal comment period from July 10, 2013 through August
23, 2013. Ballot pools are forming now through August 8, 2013. A ballot and non-binding poll of the
associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) will be conducted August
14-23, 2013.
Unofficial Comment Form
Project 2007-17.2 PSMT Phase 2 (Reclosing Relays) – July 2013
2
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained. Insert a “check” mark in the appropriate boxes by doubleclicking the gray areas.
NOTE: The Standards Authorization Request specifically limits this project to modifying PRC-005-2 to
address the addition of reclosing relays which can affect the reliability of the BES, and specifically
precludes general improvements to PRC-005-2.
1. In response to comments, the drafting team revised the previously-posted draft of PRC-005-3 and
the Supplementary Reference and FAQ document. Do you agree with these changes? If not, please
provide specific suggestions for improvement.
Yes
No
Comments:
2. In response to comments, the drafting team developed an “Implementation Plan for Newly
identified Automatic Reclosing Components due to generation changes in the Balancing Authority
Area” Do you agree with this additional Implementation Plan? If not, please provide specific
suggestions for improvement.
Yes
No
Comments:
Unofficial Comment Form
Project 2007-17.2 PSMT Phase 2 (Reclosing Relays) – July 2013
3
Attachment 6c
Updated SAR Form
Standards Committee January 17, 2013 Agenda
E-mail completed form to
[email protected]
Standard Authorization Request Form
Request Date
January 17, 2013
SAR Requester Information
SAR Type (Check a box for each one that applies.)
Individual, Group, or Committee Name
Protection System Maintenance
Standard Drafting Team
New Standard
Primary Contact (if Group or Committee)
Charles Rogers
Revision to existing Standard
Company or Group Name
Chairman, Protection System
Maintenance Standard Drafting Team
Withdrawal of existing Standard
E-mail
Project Identified in Reliability Standards
Development Plan
(Project Number and Name:
)
Telephone
[email protected]
517-788-0027
Modification to NERC Glossary term or addition
of new term
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Brief Description of Proposed Standard Modifications/Actions (In three sentences or less, summarize the
proposed actions a drafting team will be responsible for implementing.)
The Standard Drafting Team shall modify NERC Standard PRC-005-2 to explicitly address the
maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk Electric
System.
The Standard Drafting Team shall not make general revisions to the standard in content or arrangement.
Need (Explain why the Standard is being developed or modified. Clearly indicate why the actions being
proposed are needed for maintaining or improving bulk power system reliability, including an assessment
of the reliability and market interface impacts. This is similar to the Purpose statement in a Reliability
Standard.)
Reclosing relays are applied to facilitate automatic restoration of system components following a
Protection System operation. In certain circumstances the misoperation of reclosing relays can impact
the reliability of the Bulk Electric System. The Federal Energy Regulatory Commission, in paragraphs 1627 of Order No. 758, directed that NERC include reclosing relays that “can affect the reliable operation
of the Bulk-Power System” within NERC Standard PRC-005.
Modifying the standard in this fashion will assure that those reclosing relays that can affect the
reliability of the Bulk Electric System are properly maintained.
No market interface impacts are anticipated.
Goals (Describe what must be accomplished in order to meet the above need. This section would become
the Requirements in a Reliability Standard.)
The revision to PRC-005-2 may require that the definition of Protection System be revised to add
reclosing relays.
The Applicability section of the Standard must be modified to describe explicitly those devices that
entities are to maintain in accordance with the revised standard.
The Tables of minimum maintenance activities and maximum maintenance intervals will require
modification to include appropriate intervals and activities.
Finally, the informative Supplementary Reference Document (provided as a technical reference for PRC005-2) should be modified to provide the rationale for the maintenance activities and intervals within
the modified standard, as well as to provide application guidance to industry.
Standards Authorization Request Form
2
Objectives and/or Potential Future Metrics (Describe what the potential measure or criteria for success
may be for determining the successful implementation of this request. Provide ideas for potential metrics
to be developed and monitored in the future relative to this request, if any.)
Successful implementation of the modified standard will assure that the devices being added will
perform as needed for the conditions anticipated by those performance requirements.
Detailed Description (In three paragraphs or more, provide a detailed description of the proposed actions
a drafting team will be responsible for executing so that the team can efficiently implement this request.
While you will check applicability boxes on the following page, this description must include proportional
identification of to whom the standard should apply among industry participants.)
The drafting team shall:
1. Consider revision of the title of the Standard to appropriately address the added devices.
2. Modify the Purpose of the Standard as necessary to address reclosing relays.
3. Consider modification of the definition of Protection System to add reclosing relays.
4. Modify the Applicability section of PRC-005-2 to describe explicitly those devices that entities are
to maintain in accordance with the revised standard.
5. Modify the Tables within PRC-005-2 to include maximum intervals and minimum activities
appropriate for the devices being addressed, with consideration for the technology of the
devices and for any condition monitoring that may be in place for those devices.
6. Modify the Measures and Violation Severity Levels as necessary to address the modified
requirements.
7. Modify the informative Supplementary Reference Document (provided as a technical reference
for PRC-005-2) to provide the rationale for the maintenance activities and intervals within the
modified standard, as well as to provide application guidance to industry.
OPTIONAL: Technical Analysis Performed to Support Justification (Provide the results of any technical
study or analysis performed to justify this request. Alternatively, if deemed necessary, propose a technical
study or analysis that should be performed prior to a related standard development project being initiated
in response to this request.)
The NERC System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) have jointly performed a technical study to determine which reclosing relays
should be addressed within PRC-005 and provide advice regarding appropriate maintenance intervals
and activities for those relays. The related report was approved by the NERC Planning Committee on
November 14, 2012.
The Standard Drafting Team shall use this report as an aid in developing appropriate revisions to
PRC-005-2.
Standards Authorization Request Form
3
Reliability Functions
The Standard(s) May Apply to the Following Functions (Check box for each one that applies.)
Regional
Entity
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of the
Bulk Electric System within the region and adjacent regions.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
Standards Authorization Request Form
4
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and reliability-related services) to
serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard(s) comply with all of the following Market Interface Principles? (Select ‘yes’
or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
Standards Authorization Request Form
5
3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.
Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive information. All
market participants shall have equal opportunity to access commercially non-sensitive information
that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
NONE
Related Projects
Project ID and Title
Explanation
NONE
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Standards Authorization Request Form
6
Attachment 6c
Updated SAR Form
Standards Committee January 17, 2013 Agenda
E-mail completed form to
[email protected]
Standard Authorization Request Form
Request Date
January 17, 2013
SAR Requester Information
SAR Type (Check a box for each one that applies.)
Individual, Group, or Committee Name
Protection System Maintenance
Standard Drafting Team
New Standard
Primary Contact (if Group or Committee)
Charles Rogers
Revision to existing Standard
Company or Group Name
Chairman, Protection System
Maintenance Standard Drafting Team
Withdrawal of existing Standard
E-mail
Project Identified in Reliability Standards
Development Plan
(Project Number and Name:
)
Telephone
[email protected]
517-788-0027
Modification to NERC Glossary term or addition
of new term
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Brief Description of Proposed Standard Modifications/Actions (In three sentences or less, summarize the
proposed actions a drafting team will be responsible for implementing.)
The Standard Drafting Team shall modify NERC Standard PRC-005-2 to explicitly address the
maintenance and testing of reclosing relays which can affect the reliable operation of the Bulk Electric
System.
The Standard Drafting Team shall not make general revisions to the standard in content or arrangement.
Need (Explain why the Standard is being developed or modified. Clearly indicate why the actions being
proposed are needed for maintaining or improving bulk power system reliability, including an assessment
of the reliability and market interface impacts. This is similar to the Purpose statement in a Reliability
Standard.)
Reclosing relays are applied to facilitate automatic restoration of system components following a
Protection System operation. In certain circumstances the misoperation of reclosing relays can impact
the reliability of the Bulk Electric System. The Federal Energy Regulatory Commission, in paragraphs 1627 of Order No. 758, directed that NERC include reclosing relays that “can affect the reliable operation
of the Bulk-Power System” within NERC Standard PRC-005.
Modifying the standard in this fashion will impact Bulk Electric System (BES) reliability by assureing that
those reclosing relays that can affect the reliability of the Bulk Electric System are properly
maintained(installed to meet performance goals of approved NERC Standards) are properly maintained
so that they may be expected to perform properly.
No market interface impacts are anticipated.
Goals (Describe what must be accomplished in order to meet the above need. This section would become
the Requirements in a Reliability Standard.)
The revision to PRC-005-2 may require that the definition of Protection System be revised to add
reclosing relays.
The Applicability section of the Standard must be modified to describe explicitly those devices that
entities are to maintain in accordance with the revised standard.
The Tables of minimum maintenance activities and maximum maintenance intervals will require
modification to include appropriate intervals and activities.
Finally, the informative Supplementary Reference Document (provided as a technical reference for PRC005-2) should be modified to provide the rationale for the maintenance activities and intervals within
the modified standard, as well as to provide application guidance to industry.
Standards Authorization Request Form
2
Standards Authorization Request Form
3
Objectives and/or Potential Future Metrics (Describe what the potential measure or criteria for success
may be for determining the successful implementation of this request. Provide ideas for potential metrics
to be developed and monitored in the future relative to this request, if any.)
Successful implementation of the modified standard will assure that the devices being added will
perform as needed for the conditions anticipated by those performance requirements.
Detailed Description (In three paragraphs or more, provide a detailed description of the proposed actions
a drafting team will be responsible for executing so that the team can efficiently implement this request.
While you will check applicability boxes on the following page, this description must include proportional
identification of to whom the standard should apply among industry participants.)
The drafting team shall:
1. Consider revision of the title of the Standard to appropriately address the added devices.
2. Modify the Purpose of the Standard as necessary to address reclosing relays.
3. Consider modification of the definition of Protection System to add reclosing relays.
4. Modify the Applicability section of PRC-005-2 to describe explicitly those devices that entities are
to maintain in accordance with the revised standard.
5. Modify the Tables within PRC-005-2 to include maximum intervals and minimum activities
appropriate for the devices being addressed, with consideration for the technology of the
devices and for any condition monitoring that may be in place for those devices.
6. Modify the Measures and Violation Severity Levels as necessary to address the modified
requirements.
7. Modify the informative Supplementary Reference Document (provided as a technical reference
for PRC-005-2) to provide the rationale for the maintenance activities and intervals within the
modified standard, as well as to provide application guidance to industry.
OPTIONAL: Technical Analysis Performed to Support Justification (Provide the results of any technical
study or analysis performed to justify this request. Alternatively, if deemed necessary, propose a technical
study or analysis that should be performed prior to a related standard development project being initiated
in response to this request.)
The NERC System Analysis and Modeling Subcommittee (SAMS) and System Protection and Control
Subcommittee (SPCS) have jointly performed a technical study to determine which reclosing relays
should be addressed within PRC-005 and provide advice regarding appropriate maintenance intervals
and activities for those relays. The related report was approved by the NERC Planning Committee on
November 14, 2012.
The Standard Drafting Team shall use this report as an aid in developing appropriate revisions to
PRC-005-2.
Standards Authorization Request Form
4
Reliability Functions
The Standard(s) May Apply to the Following Functions (Check box for each one that applies.)
Regional
Entity
Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of the
Bulk Electric System within the region and adjacent regions.
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
Standards Authorization Request Form
5
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and reliability-related services) to
serve the End-use Customer.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard(s) comply with all of the following Market Interface Principles? (Select ‘yes’
or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
Standards Authorization Request Form
6
3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.
Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive information. All
market participants shall have equal opportunity to access commercially non-sensitive information
that is required for compliance with reliability standards. Yes
Related Standards
Standard No.
Explanation
NONE
Related Projects
Project ID and Title
Explanation
NONE
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Standards Authorization Request Form
7
Violation Risk Factor and Violation
Severity Level Justifications
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC-005-2 - Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria – VRFs
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning
time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to
hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC VRF Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that VRFs assigned to Requirements of Reliability Standards in
these identified areas appropriately reflect their historical critical impact on the reliability of the
Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement VRF assignments and
the main Requirement VRF assignment.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
2
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of VRFs corresponding to Requirements that address
similar reliability goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the VRF Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms
to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and
4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s
Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the requirements.
PRC-005-3 Protection System and Automatic Reclosing Maintenance is a revision of PRC-005-2
Protection System Maintenance with the stated purpose: To document and implement programs for
the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) so that they are kept in working order.
PRC-005-3 has five (5) requirements that address the inclusion of Automatic Reclosing. A Table of
minimum maintenance activities and maximum maintenance intervals has been added to PRC-005-2
to address FERC’s directives from Order 758. The revised standard requires that entities develop an
appropriate Protection System Maintenance Program (PSMP), that they implement their PSMP, and
that, in the event they are unable to restore Automatic Reclosing Components to proper working
order while performing maintenance, they initiate the follow-up activities necessary to resolve those
maintenance issues.
The requirements of PRC-005-3 map one-to-one with the requirements of PRC-005-2. The drafting
team did not revise the VRFs for the requirements of PRC-005-3.
PRC-005-3 Requirements R1 and R2 are related to developing and documenting a Protection System
Maintenance Program. The Standard Drafting Team determined that the assignment of a VRF of
Medium was consistent with the NERC criteria that violations of these requirements could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system but are unlikely to lead to bulk electric system
instability, separation, or cascading failures. Additionally, a review of the body of existing NERC
Standards with approved VRFs revealed that requirements with similar reliability objectives in other
standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
3
PRC-005-3 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC-005-3 Requirement R5 relates to the initiation of resolution of unresolved maintenance issues,
which describe situations where an entity was unable to restore a Component to proper working
order during the performance of the maintenance activity. The Standard Drafting Team determined
that the assignment of a VRF of Medium was consistent with the NERC criteria that violation of this
requirements could directly affect the electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric system but are unlikely to lead to bulk
electric system instability, separation, or cascading failures. Additionally, a review of the body of
existing NERC Standards with approved VRFs revealed that requirements with similar reliability
objectives in other standards are largely assigned a VRF of Medium.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
4
NERC Criteria - VSLs
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
5
FERC Order on VSLs
In its June 19, 2008 Order on VSLs, FERC indicated it would use the following four guidelines for determining whether to approve VSLs:
Guideline 1: VSL Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.
Guideline 2: VSL Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: VSL Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: VSL Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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VRF and VSL Justifications
VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to PRC005-2 Requirement R1.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
7
VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time-based or
performance-based
maintenance, or a
combination of both. (Part 1.1)
OR
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based
maintenance, or a combination
of both. (Part 1.1)
High
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
OR
VRF and VSL Justifications
Project 2007-17.2 – PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
8
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to include applicable
station batteries in a timebased program (Part 1.1)
Moderate
High
Severe
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Component Type consistent
with the maintenance intervals
specified in Tables 1-1 through 15, Table 2, Table 3, and Table 4-1
through 4-2 where monitoring is
used to extend the maintenance
intervals beyond those specified
for unmonitored Components.
(Part 1.2).
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
9
VRF and VSL Justifications – PRC-005-3, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
VSL Level Assignments Should
Ensure Uniformity and
Consistency in the
Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
10
VRF and VSL Justifications – PRC-005-3, R1
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to
PRC-005-2 Requirement R1.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
12
VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R2
Lower
The responsible entity uses
performance-based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
13
Proposed VSL – PRC-005-3, R2
Lower
Moderate
High
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a Segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the Segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
Segment.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
14
VRF and VSL Justifications – PRC-005-3, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
15
VRF and VSL Justifications – PRC-005-3, R2
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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VRF and VSL Justifications – PRC-005-3, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
17
Proposed VSL – PRC-005-3, R3
Lower
Moderate
High
Severe
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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VRF and VSL Justificati3ons – PRC-005-3, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
19
VRF and VSL Justifications – PRC-005-3, R3
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
20
VRF and VSL Justifications – PRC-005-3, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
21
Proposed VSL – PRC-005-3, R4
Lower
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Component Type
in accordance with their
performance-based PSMP.
Moderate
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
High
Severe
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance-based
PSMP.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
22
VRF and VSL Justifications – PRC-005-3, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
23
VRF and VSL Justifications – PRC-005-3, R4
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
24
VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from malperforming Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only requirement within approved Standards, PRC-004-2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC-022-1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC-003-2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal-performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
26
VRF and VSL Justifications – PRC-005-3, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The Requirement in PRC-005-2 has not been implemented; consequently, there is no prior level of
compliance.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R5
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | June 2013
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Violation Risk Factor and Violation
Severity Level Justifications
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in PRC-005-2 - Protection System
Maintenance.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support
the determination of an initial value range for the Base Penalty Amount regarding violations of
requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction Guidelines.
The Protection System Maintenance and Testing Standard Drafting Team applied the following NERC
criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria – VRFs
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures; or, a requirement in a planning
time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of a medium risk requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could,
under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and
adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the
preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to
hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC VRF Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that VRFs assigned to Requirements of Reliability Standards in
these identified areas appropriately reflect their historical critical impact on the reliability of the
Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement VRF assignments and
the main Requirement VRF assignment.
VRF and VSL JustificationsVRF and VSL Justifications
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Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of VRFs corresponding to Requirements that address
similar reliability goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the VRF Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms
to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The
team did not address Guideline 1 directly because of an apparent conflict between Guidelines 1 and
4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within NERC’s
Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the requirements.
PRC-005-3 Protection System and Automatic Reclosing Maintenance is a revision of PRC-005-2
Protection System Maintenance with the stated purpose: To document and implement programs for
the maintenance of all Protection Systems and Automatic Reclosing affecting the reliability of the
Bulk Electric System (BES) so that they are kept in working order.
PRC-005-3 has five (5) requirements that address the inclusion of Automatic Reclosing. A Table of
minimum maintenance activities and maximum maintenance intervals has been added to PRC-005-2
to address FERC’s directives from Order 758. The revised standard requires that entities develop an
appropriate Protection System Maintenance Program (PSMP), that they implement their PSMP, and
that, in the event they are unable to restore Automatic Reclosing Components to proper working
order while performing maintenance, they initiate the follow-up activities necessary to resolve those
maintenance issues.
The requirements of PRC-005-3 map one-to-one with the requirements of PRC-005-2. The drafting
team did not revise the VRFs for the requirements of PRC-005-3.
PRC-005-3 Requirements R1 and R2 are related to developing and documenting a Protection System
Maintenance Program. The Standard Drafting Team determined that the assignment of a VRF of
Medium was consistent with the NERC criteria that violations of these requirements could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system but are unlikely to lead to bulk electric system
instability, separation, or cascading failures. Additionally, a review of the body of existing NERC
Standards with approved VRFs revealed that requirements with similar reliability objectives in other
standards are largely assigned a VRF of Medium.
VRF and VSL JustificationsVRF and VSL Justifications
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3
PRC-005-3 Requirements R3 and R4 are related to implementation of the Protection System
Maintenance Program. The SDT determined that the assignment of a VRF of High was consistent
with the NERC criteria that that violation of these requirements could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.
Additionally, a review of the body of existing NERC Standards with approved VRFs revealed that
requirements with similar reliability objectives in other standards are assigned a VRF of High.
PRC-005-3 Requirement R5 relates to the initiation of resolution of unresolved maintenance issues,
which describe situations where an entity was unable to restore a Component to proper working
order during the performance of the maintenance activity. The Standard Drafting Team determined
that the assignment of a VRF of Medium was consistent with the NERC criteria that violation of this
requirements could directly affect the electrical state or the capability of the bulk electric system, or
the ability to effectively monitor and control the bulk electric system but are unlikely to lead to bulk
electric system instability, separation, or cascading failures. Additionally, a review of the body of
existing NERC Standards with approved VRFs revealed that requirements with similar reliability
objectives in other standards are largely assigned a VRF of Medium.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
4
NERC Criteria - VSLs
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
Component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
VRF and VSL JustificationsVRF and VSL Justifications
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FERC Order on VSLs
In its June 19, 2008 Order on VSLs, FERC indicated it would use the following four guidelines for determining whether to approve VSLs:
Guideline 1: VSL Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.
Guideline 2: VSL Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: VSL Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: VSL Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications
VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
NERC VRF Discussion
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements so only one VRF was assigned. The requirement utilizes Parts to
identify the items to be included within a Protection System Maintenance Program. The VRF for this
requirement is consistent with others in the standard with regard to relative risk; therefore, there is no
conflict.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to PRC005-2 Requirement R1.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
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VRF and VSL Justifications – PRC-005-3, R1
Proposed VRF
Medium
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to establish a Protection System Maintenance Program (PSMP) for Protection Systems designed to
provide protection for BES Element(s) could directly affect the electrical state or the capability of the bulk
power system. However, violation of this requirement is unlikely to lead to bulk power system instability,
separation, or cascading failures. The applicable entities are always responsible for maintaining the reliability
of the bulk power system regardless of the situation. This VRF emphasizes the risk to system performance
that results from mal-performing Protection System Components. Failure to establish a Protection System
Maintenance Program (PSMP) for Protection Systems will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to specify whether one
Component Type is being
addressed by time-based or
performance-based
maintenance, or a
combination of both. (Part 1.1)
OR
Moderate
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based
maintenance, or a combination
of both. (Part 1.1)
High
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
OR
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 – PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
Severe
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance,
or a combination of both. (Part
1.1).
8
Proposed VSL – PRC-005-3, R1
Lower
The responsible entity’s PSMP
failed to include applicable
station batteries in a timebased program (Part 1.1)
Moderate
High
Severe
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to
each Component Type consistent
with the maintenance intervals
specified in Tables 1-1 through 15, Table 2, Table 3, and Table 4-1
through 4-2 where monitoring is
used to extend the maintenance
intervals beyond those specified
for unmonitored Components.
(Part 1.2).
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R1
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards being
replaced by this proposed standard.
FERC VSL G2
VSL Level Assignments Should
Ensure Uniformity and
Consistency in the
Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and consistency
in the determination of similar penalties for similar violations.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R1
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
NERC VRF Discussion
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report: N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The SDT has determined that there is no consistency among existing approved Standards relative to
requirements of this nature. The SDT has assigned a MEDIUM VRF, which is consistent with recent FERC
guidance on FAC-008-3 Requirement R2 and FAC-013-2 Requirement R1, which are similar in nature to
PRC-005-2 Requirement R1.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to properly establish a performance-based Protection System Maintenance Program (PSMP) for.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R2
Proposed VRF
Medium
Protection Systems designed to provide protection for BES Element(s) could directly affect the electrical
state or the capability of the bulk power system. However, violation of this requirement is unlikely to lead
to bulk power system instability, separation, or cascading failures. The applicable entities are always
responsible for maintaining the reliability of the bulk power system regardless of the situation. This VRF
emphasizes the risk to system performance that results from mal-performing Protection System
Components. Failure to properly establish a performance-based Protection System Maintenance Program
(PSMP) for Protection Systems will not, by itself, lead to instability, separation, or cascading failures. Thus,
the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R2
Lower
The responsible entity uses
performance-based
maintenance intervals in its
PSMP but failed to reduce
Countable Events to no more
than 4% within three years.
Moderate
N/A
High
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no
more than 4% within four years.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
Severe
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
13
Proposed VSL – PRC-005-3, R2
Lower
Moderate
High
Severe
OR
2) Failed to reduce countable
events to no more than 4% within
five years
OR
3) Maintained a Segment with less
than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater of
5% of the Segment population
or 3 Components,
OR
• Annually analyze the program
activities and results for each
Segment.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R2
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R2
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R3
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
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Proposed VSL – PRC-005-3, R3
Lower
Moderate
High
Severe
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included
within a time-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance
intervals prescribed within
Tables 1-1 through 1-5, Table 2,
Table 3, and Table 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15%
or less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Table 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the
total Components included within
a specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
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VRF and VSL Justificati3ons – PRC-005-3, R3
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
19
VRF and VSL Justifications – PRC-005-3, R3
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
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VRF and VSL Justifications – PRC-005-3, R4
Proposed VRF
High
NERC VRF Discussion
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only Reliability Standards with similar goals are those being replaced by this standard, and the High
VRF assignment for this requirement is consistent with the assigned VRFs for companion requirements in
those existing standards.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement and follow its Protection System Maintenance Program (PSMP) could, under
emergency, abnormal, or restorative conditions anticipated by the preparations, directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures, or
could hinder restoration to a normal condition. Thus, this requirement meets the criteria for a High VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
21
Proposed VSL – PRC-005-3, R4
Lower
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain 5% or less of the
annual scheduled maintenance
for a specific Component Type
in accordance with their
performance-based PSMP.
Moderate
For Components included
within a performance-based
maintenance program, the
responsible entity failed to
maintain more than 5% but
10% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
High
Severe
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a
specific Component Type in
accordance with their
performance-based PSMP.
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Component Type in accordance
with their performance-based
PSMP.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
22
VRF and VSL Justifications – PRC-005-3, R4
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
This VSL is consistent with the current VSLs associated with the existing requirements of the standards
being replaced by this proposed standard.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
23
VRF and VSL Justifications – PRC-005-3, R4
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
24
VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
NERC VRF Discussion
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system. However, violation of
this requirement is unlikely to lead to bulk power system instability, separation, or cascading failures. The
applicable entities are always responsible for maintaining the reliability of the bulk power system
regardless of the situation. This VRF emphasizes the risk to system performance that results from malperforming Protection System Components. Failure to initiate resolution of an unresolved maintenance
issue for a Protection System Component will not, by itself, lead to instability, separation, or cascading
failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2 Discussion
Guideline 2- Consistency within a Reliability Standard:
The requirement has no subpart(s); therefore, only one VRF was assigned and no conflict(s) exist.
FERC VRF G3 Discussion
Guideline 3- Consistency among Reliability Standards:
The only requirement within approved Standards, PRC-004-2a Requirements R1 and R2 contain a similar
requirement and is assigned a HIGH VRF. However, these requirements contain several subparts, and the
VRF must address the most egregious risk related to these subparts, and a comparison to these
requirements may be irrelevant. PRC-022-1 Requirement R1.5 contains only a similar requirement, and is
assigned a MEDIUM VRF. FAC-003-2 Requirement R5 contains only a similar requirement, and is assigned
a MEDIUM VRF.
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to initiate resolution of an unresolved maintenance issue for a Protection System Component
could directly affect the electrical state or the capability of the bulk power system.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R5
Proposed VRF
Medium
However, violation of this requirement is unlikely to lead to bulk power system instability, separation, or
cascading failures. The applicable entities are always responsible for maintaining the reliability of the bulk
power system regardless of the situation. This VRF emphasizes the risk to system performance that results
from mal-performing Protection System Components. Failure to initiate resolution of an unresolved
maintenance issue for a Protection System Component will not, by itself, lead to instability, separation, or
cascading failures. Thus, the requirement meets NERC’s criteria for a Medium VRF.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
This requirement establishes a single risk-level, and the assigned VRF is consistent with that risk level.
Proposed VSL – PRC-005-3, R5
Lower
Moderate
The responsible entity failed to
undertake efforts to correct 5
or fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct
greater than 5, but less than or
equal to 10 identified
Unresolved Maintenance
Issues.
High
The responsible entity failed to
undertake efforts to correct
greater than 10, but less than or
equal to 15 identified Unresolved
Maintenance Issues.
VRF and VSL JustificationsVRF and VSL Justifications
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Severe
The responsible entity failed to
undertake efforts to correct
greater than 15 identified
Unresolved Maintenance Issues.
26
VRF and VSL Justifications – PRC-005-3, R5
NERC VSL Guidelines
Meets NERC’s VSL Guidelines—There is an incremental aspect to the violation and the VSLs follow the
guidelines for incremental violations.
FERC VSL G1
VSL Assignments Should Not
Have the Unintended
Consequence of Lowering the
Current Level of Compliance
The Requirement in PRC-005-2 has not been implemented; consequently, there is no prior level of
compliance.
FERC VSL G2
VSL Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single VSL
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: VSL Assignments
that Contain Ambiguous
Language
Guideline 2a:
N/A
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
VRF and VSL JustificationsVRF and VSL Justifications
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VRF and VSL Justifications – PRC-005-3, R5
FERC VSL G3
VSL Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses similar terminology to that used in the associated requirement, and is therefore
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
VSL Assignment Should Be
Based on A Single Violation, Not
on A Cumulative Number of
Violations
VRF and VSL JustificationsVRF and VSL Justifications
Project 2007-17.2 PRC-005-3: Protection System and Automatic Reclosing Maintenance | AprilJune 2013
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``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
July 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ............. 2
2.2 Protection System Definition ............................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards................................ 3
2.3.1 Frequently Asked Questions: ........................................................................................ 4
2.4.1 Frequently Asked Questions: ........................................................................................ 6
3. Protection System and Automatic Reclosing Product Generations ........................................... 9
4. Definitions ................................................................................................................................. 11
4.1 Frequently Asked Questions: ......................................................................................... 12
5. Time-Based Maintenance (TBM) Programs .............................................................................. 14
5.1 Maintenance Practices..................................................................................................... 14
5.1.1 Frequently Asked Questions: .................................................................................. 16
5.2 Extending Time-Based Maintenance ......................................................................... 17
5.2.1 Frequently Asked Questions: .................................................................................. 18
6. Condition-Based Maintenance (CBM) Programs ...................................................................... 19
6.1 Frequently Asked Questions: .............................................................................................. 19
7. Time-Based Versus Condition-Based Maintenance .................................................................. 21
7.1 Frequently Asked Questions: ......................................................................................... 21
8. Maximum Allowable Verification Intervals .............................................................................. 27
8.1 Maintenance Tests ........................................................................................................... 27
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 27
ii
PRC-005-3 Supplementary Reference and FAQ – July 2013
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4 ................. 29
8.1.3 Frequently Asked Questions: .................................................................................. 30
8.2 Retention of Records ....................................................................................................... 35
8.2.1 Frequently Asked Questions: .................................................................................. 35
8.3 Basis for Table 1 Intervals.............................................................................................. 37
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .................... 38
9. Performance-Based Maintenance Process ............................................................................... 41
9.1 Minimum Sample Size ..................................................................................................... 42
9.2 Frequently Asked Questions: ......................................................................................... 44
10. Overlapping the Verification of Sections of the Protection System ....................................... 55
10.1 Frequently Asked Questions: ....................................................................................... 55
11. Monitoring by Analysis of Fault Records ................................................................................ 56
11.1 Frequently Asked Questions: ....................................................................................... 57
12. Importance of Relay Settings in Maintenance Programs ....................................................... 58
12.1 Frequently Asked Questions: ....................................................................................... 58
13. Self-Monitoring Capabilities and Limitations ......................................................................... 61
13.1 Frequently Asked Questions: ....................................................................................... 62
14. Notification of Protection System or Automatic Reclosing Failures ...................................... 63
15. Maintenance Activities ........................................................................................................... 64
15.1 Protective Relays (Table 1-1) ...................................................................................... 64
15.1.1 Frequently Asked Questions: ................................................................................ 64
15.2 Voltage & Current Sensing Devices (Table 1-3) ................................................... 64
15.2.1 Frequently Asked Questions: ................................................................................ 66
15.3 Control circuitry associated with protective functions (Table 1-5) .................... 67
15.3.1 Frequently Asked Questions: ................................................................................ 69
iii
PRC-005-3 Supplementary Reference and FAQ – July 2013
15.4 Batteries and DC Supplies (Table 1-4) ................................................................... 71
15.4.1 Frequently Asked Questions: ................................................................................ 71
15.5 Associated communications equipment (Table 1-2) ................................................ 86
15.5.1 Frequently Asked Questions: ................................................................................ 87
15.6 Alarms (Table 2) ............................................................................................................ 90
15.6.1 Frequently Asked Questions: ................................................................................ 90
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) .................................... 91
15.7.1 Frequently Asked Questions: ................................................................................ 91
15.8 Automatic Reclosing (Table 4) .......................................................................................... 92
15.8.1 Frequently-asked Questions .......................................................................................... 92
15.9 Examples of Evidence of Compliance ......................................................................... 93
15.9.1 Frequently Asked Questions:.................................................................................... 93
References .................................................................................................................................... 95
Figures ........................................................................................................................................... 97
Figure 1: Typical Transmission System............................................................................... 97
Figure 2: Typical Generation System .................................................................................. 98
Figure 1 & 2 Legend – Components of Protection Systems ......................................................... 99
Appendix A .................................................................................................................................. 100
Appendix B .................................................................................................................................. 103
Protection System Maintenance Standard Drafting Team ................................................. 103
iv
PRC-005-3 Supplementary Reference and FAQ – July 2013
1. Introduction and Summary
Note: This supplementary reference for PRC-005-3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC-005-1b — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs.
Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC-005-3 will replace
PRC-005-2 which combined and replaced PRC-005, PRC-008, PRC-011 and PRC-017. PRC-005-3
adds Automatic Reclosing to PRC-005-2. PRC-005-2 addressed these directed modifications and
replaces PRC-005, PRC-008, PRC-011 and PRC-017.
FERC Order 758 further directed that maintenance of reclosing relays that affect the reliable
operation of the Bulk Power System be addressed. PRC-005-3 addresses this directive, and,
when approved, will supersede PRC-005-2.
This document augments the Supplementary Reference and FAQ previously developed for PRC005-2 by including discussion relevant to Automatic Reclosing added in PRC-005-3.
PRC-005-3 Supplementary Reference and FAQ – July 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation - a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed - can result
in equipment damage, personnel hazards, and wide-area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC-005-3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC-005-3 Supplementary Reference and FAQ – July 2013
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in-force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non-transmission voltage level (Distribution
PRC-005-3 Supplementary Reference and FAQ – July 2013
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-3 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
PRC-005-2 replaced the existing PRC-005, PRC-008, PRC-011 and PRC-017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock-out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC-005-2 replaced PRC-011, it will be important to make the distinction
between under-voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC-011 is now applicable under PRC-005-2. An example of an under-voltage
load-shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC-005-3 Supplementary Reference and FAQ – July 2013
4
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-3 applies to this
equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non-BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip-test requirements. For these devices that are otherwise non-BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock-out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC-005-2, the drafting team combined legacy standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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The intent of the drafting team is that the legacy standards be reflected in PRC-005-2 as
follows:
•
•
•
•
•
Applicability of PRC-005-1b for Protection Systems relating to non-generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC-008-0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC-011-0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC-017-0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC-005-1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip-free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage-sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC-005-3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the BES
bus located at generating plant substations where the total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at substations
one bus away from generating plants specified in Section 4.2.6.1 when the
substation is less than 10 circuit-miles from the generating plant substation.
4.2.6.3 Automatic Reclosing applied as an integral part of a SPS specified in Section
4.2.4.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
a close-in three-phase fault present for twice the normal clearing time (capturing a minimum
trip-close-trip time delay) does not result in a total loss of gross generation in the
Interconnection exceeding the gross capacity of the largest BES unit within the Balancing
Authority Area where the Automatic Reclosing is applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal-performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when premature
autoreclosing has the potential to cause generating unit or plant instability. A technical report,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”, is
referenced in PRC-005-3 and provides a more detailed discussion of these concerns.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the lowvoltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low-voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2-2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC-005-3 testing requirements because the SDT is unaware
of industry-recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
with the currently-approved PRC-005-1b, consistent with the SAR for Project 2007-17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
PRC-005-3 Supplementary Reference and FAQ – July 2013
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maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non-electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2-2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock-out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
PRC-005-3 Supplementary Reference and FAQ – July 2013
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3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor-based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
•
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
•
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current-measuring devices, and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc.).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand-held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessorPRC-005-3 Supplementary Reference and FAQ – July 2013
9
based device that results in a “lock-out.” Thus, the software-latch 86 that replaces an electromechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and automatic reclosing components are kept in working order and proper operation of
malfunctioning components is restored. A maintenance program for a specific component
includes one or more of the following activities:
•
Verify — Determine that the component is functioning correctly.
•
Monitor — Observe the routine in-service operation of the component.
•
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
•
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Includes the following Components:
•
•
Reclosing relay
Control circuitry associated with the reclosing relay .
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
PRC-005-3 Supplementary Reference and FAQ – July 2013
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failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1-1 through 1-5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC-005-3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid-state protective
relays to microprocessor-based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance-time-interval-clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time-interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
PRC-005-3 Supplementary Reference and FAQ – July 2013
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management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed-end process”).
For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requiring battery replacement as part of the long-term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six-calendar-month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location - for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on-command or routinely;
the running of these tests can extend the time interval between hands-on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
•
PBM – Performance-Based Maintenance - intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBMdeveloped extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self-monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self-diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the standard, the
PRC-005-3 Supplementary Reference and FAQ – July 2013
14
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor-based Protection System or Automatic Reclosing Components that
perform continuous self-monitoring verify correct operation of most components within
the device. Self-monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self-monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with selfmonitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non-disruptive self-monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition-based Maintenance (R1) and
Performance-Based Maintenance (R2), in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance-Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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We have an electromechanical (unmonitored)) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off
off-line
line by tripping the
transformer’s high-side
side and low
low-side circuit breakers. What testing must be done
for this system?
This system is made up of component
components that are all unmonitored.. Assuming a time-based
time
Protection System Maintenance
aintenance Program schedule (as opposed to a Performance-Based
Performance
maintenance program), each component must be maintained per the most frequent hands-on
hands
activities listed in the Tables.
5.2 Extending Time-Based
Based Maintenance
All maintenance is fundamentally time
time-based. Default time-based
based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the component
componentss is not available other than observations
observat
from timebased maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self
self-monitoring device), then the intervals
ervals may be extended,
extended or
manual testing may be eliminated. This is referred to as condition
condition-based
based maintenance
or CBM. CBM is valid only for precisely the componentss subject to monitoring. In the
case of microprocessor
microprocessor-based relays, self-monitoring may not include automated
diagnostics of every component within a microprocessor.
PRC-005-33 Supplementary Reference and FAQ – July 2013
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•
Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance-Based Maintenance, or
PBM. It is also sometimes referred to as reliability-centered maintenance, or RCM; but
PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
PRC-005-3 Supplementary Reference and FAQ – July 2013
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provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1-4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device-level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1-4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1-4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
PRC-005-3 Supplementary Reference and FAQ – July 2013
20
7. Time-Based Versus Condition-Based
Maintenance
Time-based and condition-based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time-based and condition-based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards
for the Bulk-Power System, directed NERC to submit a modification to PRC-005-1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC-005-3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous - the time interval between verifications is
minutes or seconds. Thus, technically sound, condition-based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time-based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on-site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC-005-3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year - January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four-month
inspection was performed in January is due in May, but if performed in March (instead of May)
PRC-005-3 Supplementary Reference and FAQ – July 2013
21
would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
•
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented Lead-Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
PRC-005-3 Supplementary Reference and FAQ – July 2013
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1-5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
•
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented lead-acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
• A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
PRC-005-3 Supplementary Reference and FAQ – July 2013
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
•
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
PRC-005-3 Supplementary Reference and FAQ – July 2013
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•
Vented Lead-Acid battery without any alarms connected to SCADA
(unmonitored)
•
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
PRC-005-3 Supplementary Reference and FAQ – July 2013
25
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition-Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
This response may include tripping, closing, or other control actions.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely - for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters - this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications-assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub-systems of a Protection System that need to be verified are shown.
Non-distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non-distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co-located non-BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-3:
PRC-005-3 Supplementary Reference and FAQ – July 2013
27
•
First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1-1 is for protective relays,
o Table 1-2 is for the associated communications systems,
o Table 1-3 is for current and voltage sensing devices,
o Table 1-4 is for station dc supply and
o Table 1-5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make-up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
•
Next look within that table for your device and its degree of monitoring. The Tables
have different hands-on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
•
This Maintenance activity is the minimum maintenance activity that must be
documented.
•
If your Performance-Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
•
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands-on maintenance activity cycles of
this component.
•
If your Performance-Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
•
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands-on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
•
An entity does not have to utilize the extended time intervals made available by this use
of condition-based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance manhours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
PRC-005-3 Supplementary Reference and FAQ – July 2013
28
maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC-005-3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance-Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead-acid,
valve-regulated lead-acid, and nickel-cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC-005-3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC-005-3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
PRC-005-3 Supplementary Reference and FAQ – July 2013
29
properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End-to-end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications-assisted trip scheme. While
this can be interpreted as a GPS-type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally-test the dc control circuitry. A documented Real-time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real-time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1-8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology- and method-neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor- based relays.
For relay maintenance departments that choose to test microprocessor-based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor- based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
PRC-005-3 Supplementary Reference and FAQ – July 2013
31
Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real-time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
PRC-005-3 Supplementary Reference and FAQ – July 2013
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four-month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time-based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance-Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
•
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
•
Loss-of-field relays
•
Volts-per-hertz relays
•
Negative sequence overcurrent relays
•
Over voltage and under voltage protection relays
•
Stator-ground relays
•
Communications-based Protection Systems such as transfer-trip systems
•
Generator differential relays
•
Reverse power relays
•
Frequency relays
•
Out-of-step relays
•
Inadvertent energization protection
•
Breaker failure protection
For generator step-up, generator-connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
•
Transformer differential relays
PRC-005-3 Supplementary Reference and FAQ – July 2013
33
•
Neutral overcurrent relay
•
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal-conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system-connected station service transformers be included in
the Applicability. The generator-connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock-out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
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distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non-distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non-distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three-year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC-005-3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on-site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance-Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance-time-intervalclock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
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The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC-005-3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged-Fault-tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be reverified within an ongoing maintenance program. Example – it is not necessary to re-verify
correct terminal strip wiring on an ongoing basis.
PRC-005-3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC-005-3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC-005-3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in-service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in-service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1-1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto-generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built-in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I-17 (Transmission Relay System
Performance Comparison). Review of the I-17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
PRC-005-3 Supplementary Reference and FAQ – July 2013
37
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively-known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self-testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1-1 through 1-5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10-year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self-monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
•
Relay Unavailability - the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
•
Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test).
ST = 0 if there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
PRC-005-3 Supplementary Reference and FAQ – July 2013
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time-interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “timeinterval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time-interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six-year interval for the
electromechanical relay, instead of the five-year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10-year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
PRC-005-3 Supplementary Reference and FAQ – July 2013
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facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance-Based Maintenance process may be used to
establish maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based
Protection System Maintenance Program). A Performance-Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance-Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance-Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance-Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance-Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001-2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro-mechanical lock-out relays;
likewise, one segment cannot be comprised of 60 GE lock-out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
PRC-005-3 Supplementary Reference and FAQ – July 2013
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation σ, the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
PRC-005-3 Supplementary Reference and FAQ – July 2013
42
z
n = π(1 − π )
Β
2
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance-Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1-1 through 1-5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4%Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
to the requirements of the Standard. The requirements established for Performance-Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance-Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance-Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance-Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in-service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re-calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
PRC-005-3 Supplementary Reference and FAQ – July 2013
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errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human-error is not pertinent data might be in the area of testing “86” lock-out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial sixyear interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human-error caused tripping
incidents. In this example the human-error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal-performing segments in a Performance-Based Maintenance system. Some examples are
listed below.
•
The maximum allowable interval, as established by the Performance-Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
•
Identifiable sub-groups of components within the established segment, which have
been identified to be the mal-performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance-Based Maintenance program in
order to remain within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
components within the mal-performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal-performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
PRC-005-3 Supplementary Reference and FAQ – July 2013
45
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance-Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance-Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock-reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1-1-11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6-1-12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock-reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
PRC-005-3 Supplementary Reference and FAQ – July 2013
46
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance-Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance-changing criteria.
Similarly, Functional Entities that want to establish a condition-based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands-on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1-4).
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
PRC-005-3 Supplementary Reference and FAQ – July 2013
47
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six-year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC-005-3 Supplementary Reference and FAQ – July 2013
48
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V-insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper-sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC-005-3 Supplementary Reference and FAQ – July 2013
49
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real-time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC-005-3 Supplementary Reference and FAQ – July 2013
50
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Test
Total
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC-005-3 Supplementary Reference and FAQ – July 2013
51
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off-line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real-time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built-in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity-accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC-005-3 Supplementary Reference and FAQ – July 2013
52
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note - a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC-005-3 Supplementary Reference and FAQ – July 2013
53
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC-005-3 Supplementary Reference and FAQ – July 2013
54
10. Overlapping the Verification of Sections of the
Protection System
Tables 1-1 through 1-5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
•
Time-based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1-1 through 1-5;
•
Monitoring as described in Tables 1-1 through 1-5;
•
A Performance-Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
•
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC-005-3 Supplementary Reference and FAQ – July 2013
55
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time-interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance-related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
PRC-005-3 Supplementary Reference and FAQ – July 2013
56
11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC-018-1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC-002-1 and PRC-018-1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single selfmonitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non-microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
•
One or more settings are changed for any reason.
•
A relay fails and is repaired or replaced with another unit.
•
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
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58
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenanceactivity-time-interval-clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC-005-3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC-005-3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC-005-3 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC-005-3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
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The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self-monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands-on
maintenance requirement), the manufacturers of the microprocessor-based self-monitoring
components in the Protection System should publish for the user a document or map that
shows:
•
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
•
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
•
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
•
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
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13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology-neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early-generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC-005-3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor-based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
•
Non-microprocessor devices must be tested with voltage and/or current applied to the
device.
•
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber-optic Hall-effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
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protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
•
There is no specific ratio test, routine test or commissioning test mandated.
•
There is no specific documentation mandated.
•
It is required that the signal be present at the relay.
•
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
•
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
•
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
•
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real-time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
•
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
•
Another method for proving the voltage and/or current-sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
•
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current-sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all-inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
•
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
•
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi-meters, voltmeter, clamp-on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt-meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual-intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This sixyear tripping requirement can be completed as easily as tracking the Real-time Fault-clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit-interrupting device should not be confused with a motor-operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred-tripping
device without the use of communications equipment. If this high-speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay
(86) that may exist in any particular trip scheme. If the lock-out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six-year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non-BES interrupting devices are not required. Normally-open contacts
that are not used to pass a trip signal and normally-closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC-005-2, other alarming relay control circuits,
(i.e., SF-6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard-wired trip circuitry with other methods of trip-signal conveyance
such as fiber-optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber-optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC-005-3 testing requirements because the SDT is
unaware of industry-recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1b, consistent with the SAR for Project 200717, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC-005-3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1-5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC-005-3 includes high-speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non-BES circuit breaker that is tripped via a Protection
System to which PRC-005-3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non-black-start) radial Loads but has a trip that originates from an under-frequency
(81) relay.
•
The relay must be verified.
•
The voltage signal to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non-BES breaker that is tripped via a Protection
System to which PRC-005-3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non-black-start) radial Loads but has a trip that originates from a BES 115KV
line relay.
•
•
•
•
•
•
•
•
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock-out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock-out (86) (or auxiliary (94)) relay and the
non-BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non-BES breaker does not have to be proven with an electrical trip.
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non-BES circuit breaker that is tripped via a
Protection System to which PRC-005-3 applies, such as the generator field breaker and low-side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non-BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
•
The differential relay must be verified.
•
The current signals to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
•
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally-closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
•
Protective relays which respond to electrical quantities,
•
Communications Systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1-4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance-Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance-changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC-005-3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1-4.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1-4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1-4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
•
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor-based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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•
Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one- to twosecond delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
•
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
•
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc-supplied equipment in the station should be considered before using this
approach.
•
Manufacturers of microprocessor-controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
•
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
•
Internal ohmic measurements of the cells and units of lead-acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
•
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1-4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve-regulated lead-acid, vented
lead-acid, or nickel-cadmium) and the maintenance activity chosen.
For example, if you have a valve-regulated lead-acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the sixmonth interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead-acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six-months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve-regulated lead-acid (VRLA) batteries and vented lead-acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer-supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead-acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel-cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve-regulated lead-acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1-4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell-to-cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1-4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1-4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell-to-cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1-4 by a Performance-Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1-4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1-4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot-checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally-accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel-cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel-cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel-cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel-cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel-cadmium batteries,
there are no significantly measurable properties of the nickel-cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1-4(c)
(Protection System Station dc supply Using nickel-cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check-off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single checkoff attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC-005-3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve-Regulated Lead-Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead-Acid (VLA)
batteries were unable to be used on this new type of lead-acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188-2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1-4. In cases where individual cells in a multi-cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1-4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead-acid (VLA) and nickel-cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1-4. Because
the electrolyte level in valve-regulated lead-acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1-4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved-quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve-regulated lead-acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1-4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead-acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry-out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1-4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six-month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six-month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline - others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six-month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1-4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous selfmonitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1-4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1-4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1-4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1-4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1-4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1-4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1-4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications-assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications-assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communicationsassisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
•
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
•
Systems which use frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss-of-guard indication or alarm. For frequency-shift power-line carrier systems, the
guard signal level meter can also be checked.
•
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
•
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
•
On-off power-line carrier systems can be shown to be operational by automated
periodic power-line carrier check-back tests with remote alarming of failures.
•
Systems which use a frequency-shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss-of-guard alarm or low signal level alarm.
•
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
•
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
•
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
•
In many communications systems signal quality measurements, including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
•
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four-month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
•
Power Line Carrier (PLC) - The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
•
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
•
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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•
Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical-electrical signal format converters are the associated
communications equipment
Figure 1-2, A-1 and A-2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
•
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
•
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
•
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
•
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1-1 through 1-5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto-polling system; the only
requirement is that the alarm be brought to the action-site within 24 hours. This effectively
makes manned-stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned-station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non-mannedstation, which is that if the monitored point has an alarm that is auto-reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail-safe “form-b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1-1. Voltage and current-sensing devices have the same maintenance activity and
interval as Table 1-3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
•
Verify the trip path between the relay and lock-out and/or auxiliary tripping device(s).
•
Verify operation of any lock-out and/or auxiliary tripping device(s) used in the trip
circuit.
•
No verification of trip path required between the lock-out (and/or auxiliary tripping
device) and the non-BES interrupting device.
•
No verification of trip path required between the relay and trip coil for circuits that have
no lock-out and/or auxiliary tripping device(s).
•
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non-BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load-Shed relay and lock-out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock-out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under-frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non-BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock-out relay. While many failures of these distributed system circuit breakers (or
non-BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non-BES device, such as a battery bank that serves both a BES circuit breaker and a non-BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load-generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC-005-3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC-005-3.
15.8.1 Frequently-asked Questions
Automatic Reclosing is a control, not a protective function; why then is Automatic
Reclosing maintenance included in the Protection System Maintenance Program
(PSMP)?
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes (separates) the Automatic Reclosing
from the Protection System. Automatic Reclosing is included in the PSMP because it is a more
pragmatic approach as compared to creating a parallel and essentially identical ‘Control System
Maintenance Program’ for the two Automatic Reclosing component types.
Our maintenance practice consists of initiating the Automatic Reclosing relay and
confirming the breaker closes properly and the close signal is released. This practice
verifies the control circuitry associated with Automatic Reclosing. Do you agree?”
The described task partially verifies the control circuit maintenance activity. To meet the
control circuit maintenance activity, responsible entities need to verify, upon initiation, that the
reclosing relay does not issue a premature closing command. As noted on page 12 of the
SAMS/SPCS report, the concern being addressed within the standard is premature
autoreclosing that has the potential to cause generating unit or plant instability. Reclosing
applications have many variations, responsible entities will need to verify the applicability of
associated supervisor/conditional logic and the reclosing relay operation; then verify the
conditional logic or that the reclosing relay performs in a manner that does not result in a
premature closing command being issued.
Some examples of conditions which can result in a premature closing command are: an
improper supervision or conditional logic input which provides a false state and allows the
reclosing relay to issue an improper close command based on incorrect conditions (i.e. voltage
PRC-005-3 Supplementary Reference and FAQ – July 2013
92
supervision, equipment status, sync window verification); timers utilized for closing actuation
or reclosing arming/disarming circuitry which could allow the reclosing relay to issue an
improper close command; a reclosing relay output contact failure which could result in a madeup-close condition / failure-to-release condition.
Why was a close-in three phase fault present for twice the normal clearing time
chosen for the Automatic Reclosing exclusion? It exceeds TPL requirements and
ignores the breaker closing time in a trip-close-trip sequence, thus making the
exclusion harder to attain.
This condition represents a situation where a close signal is issued with no time delay or with
less time delay than is intended, such as if a reclosing contact is welded closed. This failure
mode can result in a minimum trip-close-trip sequence with the two faults cleared in primary
protection operating time, and the open time between faults equal to the breaker closing cycle
time. The sequence for this failure mode results in system impact equivalent to a high-speed
autoreclosing sequence with no delay added in the autoreclosing logic. It represents a failure
mode which must be avoided because it exceeds TPL requirements.
Do we have to test the various breaker closing circuit interlocks and controls such
as anti-pump?
These components are not specifically addressed within Table 4, and need not be individually
tested. They are indirectly verified by performing the Automatic Reclosing control circuitry
verification as established in Table 4.
For Automatic Reclosing that is not part of an SPS, do we have to close the circuit
breaker periodically?
No. For this application, you need only to verify that the Automatic Reclosing, upon initiation,
does not issue a premature closing command. This activity is concerned only with assuring that
a premature close does not occur, and cause generating plant instability.
For Automatic Reclosing that is part of an SPS, do we have to close the circuit
breaker periodically?
Yes. In this application, successful closing is a necessary portion of the SPS, and must be
verified.
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC standards that could, at times,
fulfill evidence requirements of this standard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
• Process documents or plans
• Data (such as relay settings sheets, photos, SCADA, and test records)
• Database lists, records and/or screen shots that demonstrate compliance information
• Prints, diagrams and/or schematics
PRC-005-3 Supplementary Reference and FAQ – July 2013
93
•
•
•
•
•
•
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check-off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC-016 could work for the activity tracking requirements
under this PRC-005-3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
PRC-005-3 Supplementary Reference and FAQ – July 2013
94
References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor-Based
Transmission-Line Protective Relays, Part I - Explanation of the Statistics, and Part II Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016-6
PWRD and 96WM 127-1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR- 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of ValveRegulated Lead-Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead-Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45-2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented LeadAcid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR-100248, 1006757, August 2002.
PRC-005-3 Supplementary Reference and FAQ – July 2013
95
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
19. “Considerations for Maintenance and Testing of Autoreclosing Schemes,” NERC
System Analysis and Modeling Subcommittee and NERC System Protection and
Control Subcommittee, November 2012
PRC-005-3 Supplementary Reference and FAQ – July 2013
96
Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC-005-3 Supplementary Reference and FAQ – July 2013
97
Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC-005-2, and also
may not be all-inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC-005-3 Supplementary Reference and FAQ – July 2013
98
Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Component of
Protection System
Includes
Excludes
Devices that use non-electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync-check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber-optic systems that
carry a trip signal as well as hardwired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
4
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
5
Communications
systems necessary
for correct operation
of protective
functions
Tele-protection equipment used
to convey specific information, in
the form of analog or digital
signals, necessary for the correct
operation of protective functions.
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
Additional information can be found in References
PRC-005-3 Supplementary Reference and FAQ – July 2013
99
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A-1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two-terminal pilot protection scheme to protect for line Faults, and to avoid overtripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
PRC-005-3 Supplementary Reference and FAQ – July 2013
100
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
PRC-005-3 Supplementary Reference and FAQ – July 2013
101
contacts of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally-occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC-005-3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front-panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
PRC-005-3 Supplementary Reference and FAQ – July 2013
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Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Al McMeekin
NERC
Merle Ashton
Tri-State G&T
Michael Palusso
Southern California Edison
Bob Bentert
Florida Power & Light Company
Mark Peterson
Great River Energy
Forrest Brock
Western Farmers Electric Cooperative
John Schecter
American Electric Power
Aaron Feathers
Pacific Gas and Electric Company
William D. Shultz
Southern Company Generation
Sam Francis
Oncor Electric Delivery
Eric A. Udren
Quanta Technology
Carol Gerou
Midwest Reliability Organization
Scott Vaughan
City of Roseville Electric Department
Russell C. Hardison
Tennessee Valley Authority
Matthew Westrich
American Transmission Company
David Harper
NRG Texas Maintenance Services
Philip B. Winston
Southern Company Transmission
James M. Kinney
FirstEnergy Corporation
David Youngblood
Luminant Power
Mark Lucas
ComEd
John A. Zipp
ITC Holdings
Kristina Marriott
ENOSERV
PRC-005-3 Supplementary Reference and FAQ – July 2013
103
``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
AprilJuly 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ............. 2
2.2 Protection System Definition ............................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards................................ 3
2.3.1 Frequently Asked Questions: ........................................................................................ 4
2.4.1 Frequently Asked Questions: ........................................................................................ 6
3. Protection System and Automatic Reclosing Product Generations ........................................... 9
4. Definitions ................................................................................................................................. 11
4.1 Frequently Asked Questions: ......................................................................................... 12
5. Time-Based Maintenance (TBM) Programs .............................................................................. 14
5.1 Maintenance Practices..................................................................................................... 14
5.1.1 Frequently Asked Questions: .................................................................................. 16
5.2 Extending Time-Based Maintenance ......................................................................... 17
5.2.1 Frequently Asked Questions: .................................................................................. 18
6. Condition-Based Maintenance (CBM) Programs ...................................................................... 19
6.1 Frequently Asked Questions: .............................................................................................. 19
7. Time-Based Versus Condition-Based Maintenance .................................................................. 21
7.1 Frequently Asked Questions: ......................................................................................... 21
8. Maximum Allowable Verification Intervals .............................................................................. 27
8.1 Maintenance Tests ........................................................................................................... 27
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 27
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4 ................. 29
8.1.3 Frequently Asked Questions: .................................................................................. 30
8.2 Retention of Records ....................................................................................................... 35
8.2.1 Frequently Asked Questions: .................................................................................. 35
8.3 Basis for Table 1 Intervals.............................................................................................. 37
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .................... 38
9. Performance-Based Maintenance Process ............................................................................... 41
9.1 Minimum Sample Size ..................................................................................................... 42
9.2 Frequently Asked Questions: ......................................................................................... 44
10. Overlapping the Verification of Sections of the Protection System ....................................... 55
10.1 Frequently Asked Questions: ....................................................................................... 55
11. Monitoring by Analysis of Fault Records ................................................................................ 56
11.1 Frequently Asked Questions: ....................................................................................... 57
12. Importance of Relay Settings in Maintenance Programs ....................................................... 58
12.1 Frequently Asked Questions: ....................................................................................... 58
13. Self-Monitoring Capabilities and Limitations ......................................................................... 61
13.1 Frequently Asked Questions: ....................................................................................... 62
14. Notification of Protection System or Automatic Reclosing Failures ...................................... 63
15. Maintenance Activities ........................................................................................................... 64
15.1 Protective Relays (Table 1-1) ...................................................................................... 64
15.1.1 Frequently Asked Questions: ................................................................................ 64
15.2 Voltage & Current Sensing Devices (Table 1-3) ................................................... 64
15.2.1 Frequently Asked Questions: ................................................................................ 66
15.3 Control circuitry associated with protective functions (Table 1-5) .................... 67
15.3.1 Frequently Asked Questions: ................................................................................ 69
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
15.4 Batteries and DC Supplies (Table 1-4) ................................................................... 71
15.4.1 Frequently Asked Questions: ................................................................................ 71
15.5 Associated communications equipment (Table 1-2) ................................................ 86
15.5.1 Frequently Asked Questions: ................................................................................ 87
15.6 Alarms (Table 2) ............................................................................................................ 90
15.6.1 Frequently Asked Questions: ................................................................................ 90
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) .................................... 91
15.7.1 Frequently Asked Questions: ................................................................................ 91
15.8 Automatic Reclosing (Table 4) .......................................................................................... 92
15.8.1 Frequently-asked Questions .......................................................................................... 92
15.9 Examples of Evidence of Compliance ..................................................................... 9394
15.9.1 Frequently Asked Questions:................................................................................ 9394
References .................................................................................................................................... 95
Figures ........................................................................................................................................... 97
Figure 1: Typical Transmission System............................................................................... 97
Figure 2: Typical Generation System .................................................................................. 98
Figure 1 & 2 Legend – Components of Protection Systems ......................................................... 99
Appendix A .................................................................................................................................. 100
Appendix B .................................................................................................................................. 103
Protection System Maintenance Standard Drafting Team ................................................. 103
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ......................... 2
2.2 Protection System Definition ................................................................................................ 3
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
2.3 Applicability of New Protection System Maintenance Standards ........................................ 3
2.3.1 Frequently Asked Questions: ............................................................................................. 4
2.4.1 Frequently Asked Questions: ............................................................................................. 6
3. Protection Systems Product Generations ................................................................................... 8
4. Definitions ................................................................................................................................. 10
4.1 Frequently Asked Questions: .............................................................................................. 11
5. Time-Based Maintenance (TBM) Programs .............................................................................. 13
5.1 Maintenance Practices ....................................................................................................... 13
5.1.1 Frequently Asked Questions: ....................................................................................... 15
5.2 Extending Time-Based Maintenance .............................................................................. 16
5.2.1 Frequently Asked Questions: ....................................................................................... 16
6. Condition-Based Maintenance (CBM) Programs ...................................................................... 18
6.1 Frequently Asked Questions: .............................................................................................. 18
7. Time-Based Versus Condition-Based Maintenance .................................................................. 20
7.1 Frequently Asked Questions: .............................................................................................. 20
8. Maximum Allowable Verification Intervals .............................................................................. 26
8.1 Maintenance Tests .............................................................................................................. 26
8.1.1 Table of Maximum Allowable Verification Intervals.................................................... 26
8.1.2 Additional Notes for Tables 1-1 through 1-5 and Table 3 ........................................... 28
8.1.3 Frequently Asked Questions: ....................................................................................... 29
8.2 Retention of Records .......................................................................................................... 34
8.2.1 Frequently Asked Questions: ....................................................................................... 34
8.3 Basis for Table 1 Intervals ................................................................................................... 36
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .............................. 37
9. Performance-Based Maintenance Process ............................................................................... 40
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
9.1 Minimum Sample Size......................................................................................................... 41
9.2 Frequently Asked Questions: .............................................................................................. 43
10. Overlapping the Verification of Sections of the Protection System ....................................... 54
10.1 Frequently Asked Questions: ............................................................................................ 54
11. Monitoring by Analysis of Fault Records ................................................................................ 55
11.1 Frequently Asked Questions: ............................................................................................ 56
12. Importance of Relay Settings in Maintenance Programs ....................................................... 57
12.1 Frequently Asked Questions: ............................................................................................ 57
13. Self-Monitoring Capabilities and Limitations ......................................................................... 60
13.1 Frequently Asked Questions: ............................................................................................ 61
14. Notification of Protection System Failures ............................................................................. 62
15. Maintenance Activities ........................................................................................................... 63
15.1 Protective Relays (Table 1-1) ............................................................................................ 63
15.1.1 Frequently Asked Questions: ..................................................................................... 63
15.2 Voltage & Current Sensing Devices (Table 1-3) ............................................................ 63
15.2.1 Frequently Asked Questions: ..................................................................................... 65
15.3 Control circuitry associated with protective functions (Table 1-5) .............................. 66
15.3.1 Frequently Asked Questions: ..................................................................................... 68
15.4 Batteries and DC Supplies (Table 1-4)........................................................................... 70
15.4.1 Frequently Asked Questions: ..................................................................................... 70
15.5 Associated communications equipment (Table 1-2) ........................................................ 84
15.5.1 Frequently Asked Questions: ..................................................................................... 86
15.6 Alarms (Table 2) ................................................................................................................ 89
15.6.1 Frequently Asked Questions: ..................................................................................... 89
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)............................................... 90
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
15.7.1 Frequently Asked Questions: ..................................................................................... 90
15.8 Examples of Evidence of Compliance ............................................................................... 91
15.8.1 Frequently Asked Questions: ......................................................................................... 91
References .................................................................................................................................... 93
Figures ........................................................................................................................................... 95
Figure 1: Typical Transmission System ..................................................................................... 95
Figure 2: Typical Generation System ........................................................................................ 96
Figure 1 & 2 Legend – components of Protection Systems .......................................................... 97
Appendix A .................................................................................................................................... 98
Appendix B .................................................................................................................................. 101
Protection System Maintenance Standard Drafting Team ......................................................... 101
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PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
1. Introduction and Summary
Note: This supplementary reference for PRC-005-3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC-005-1b — Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC-011-0 — UVLS System Maintenance and Testing
PRC-017-0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs.
Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC-005-3 will replace
PRC-005-2 which combined and replaced PRC-005, PRC-008, PRC-011 and PRC-017. PRC-005-3
adds Automatic Reclosing to PRC-005-2. PRC-005-2 addressed these directed modifications and
replaces PRC-005, PRC-008, PRC-011 and PRC-017.
FERC Order 758 further directed that maintenance of reclosing relays that affect the reliable
operation of the Bulk Power System be addressed. PRC-005-3 addresses this directive, and,
when approved, will supersede PRC-005-2.
This document augments the Supplementary Reference and FAQ previously developed for PRC005-2 by including discussion relevant to Automatic Reclosing added in PRC-005-3.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation - a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed - can result
in equipment damage, personnel hazards, and wide-area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC-005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC-005-3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC-005-2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
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Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
•
Protective relays which respond to electrical quantities,
•
Communications systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC-005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in-force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non-transmission voltage level (Distribution
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Provider equipment) that is wholly or partially installed to protect the BES. PRC-005-3 would
apply to this equipment. An example is underfrequency load-shedding, which is frequently
applied well down into the distribution system to meet PRC-007-0.
PRC-005-2 replaced the existing PRC-005, PRC-008, PRC-011 and PRC-017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC-008 was
constructed quite differently than the original PRC-005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock-out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC-005-2 replaced PRC-011, it will be important to make the distinction
between under-voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC-011 is now applicable under PRC-005-2. An example of an under-voltage
load-shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC-011 are the very same types of
devices needed in PRC-005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non-transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC-005-3 applies to this
equipment. An example is underfrequency load-shedding, which is frequently applied well
down into the distribution system to meet PRC-007-0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock-out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non-BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip-test requirements. For these devices that are otherwise non-BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock-out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC-005-2, the drafting team combined legacy standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
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The intent of the drafting team is that the legacy standards be reflected in PRC-005-2 as
follows:
•
•
•
•
•
Applicability of PRC-005-1b for Protection Systems relating to non-generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC-008-0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC-011-0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC-017-0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC-005-1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip-free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage-sensing devices.
Relays that respond to non-electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC-005-3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Automatic Reclosing applied on the terminals of BES Elements connected to the
BES bus located at generating plant substations where the total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at substations
one bus away from generating plants specified in Section 4.2.6.1 when the
substation is less than 10 circuit-miles from the generating plant substation.
4.2.6.3 Automatic Reclosing applied as an integral part of a SPS specified in Section
4.2.4.
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Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
a close-in three-phase fault present for twice the normal clearing time (capturing a minimum
trip-close-trip time delay) does not result in a total loss of gross generation in the
Interconnection exceeding the gross capacity of the largest BES unit within the Balancing
Authority Area where the Automatic Reclosing is applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal-performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when inadvertent premature
autoreclosing near a generating station subjects the generation station to severe fault
stresseshas the potential to cause generating unit or plant instability. A technical report,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”, is
referenced in PRC-005-3 and provides a more detailed discussion of these concerns.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the lowvoltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low-voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2-2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC-005-3 testing requirements because the SDT is unaware
of industry-recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
with the currently-approved PRC-005-1b, consistent with the SAR for Project 2007-17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
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You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non-electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2-2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock-out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
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3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor-based relays have six significant traits that impact a maintenance
strategy:
•
Self monitoring capability - the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
•
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
•
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non-Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
•
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
•
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
•
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current-measuring devices, and even the control
circuitry (in the form of software-latches replacing lock-out relays, etc.).
Any Protection System component can have self-monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand-held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessorPRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
9
based device that results in a “lock-out.” Thus, the software-latch 86 that replaces an electromechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and Automatic automatic Reclosing reclosing Components components are kept in
working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
•
Verify — Determine that the component is functioning correctly.
•
Monitor — Observe the routine in-service operation of the component.
•
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
•
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
•
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Includes the following Components:
•
•
Reclosing relay
Control circuitry associated with the reclosing relay through the close coil(s) of the
circuit breakers or similar device but excluding breaker internal controls such as
anti-pump and various interlock circuits.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual componentsComponents.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three-phase set of such
devices or a single device as a single Component.
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Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC-005-1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC-005-3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1-1 through 1-5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC-005-3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid-state protective
relays to microprocessor-based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance-time-interval-clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time-interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
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Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed-end process”).
For example, a problem might be identified on a VRLA battery during a six-month check. In
instances such as one that requiring battery replacement as part of the long-term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six-calendar-month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time-based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location - for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on-command or routinely;
the running of these tests can extend the time interval between hands-on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
•
TBM – time-based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
•
PBM – Performance-Based Maintenance - intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBMdeveloped extended intervals when test failures or in-service failures occur infrequently.
•
CBM – condition-based maintenance – continuously or frequently reported results from
non-disruptive self-monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self-diagnostics. While the term “Condition-BasedMaintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status-monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored-basis-time-intervals” existing within the standard, the
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
14
explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor-based Protection System or Automatic Reclosing Components that
perform continuous self-monitoring verify correct operation of most components within
the device. Self-monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self-monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with selfmonitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non-disruptive self-monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
•
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
•
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
•
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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TBM
1
2
3
CBM
PBM
Relationship of time-based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition-based Maintenance (R1) and
Performance-Based Maintenance (R2), in addition to simple time-based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time-based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance-Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
16
We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off
off-line
line by tripping the
transformer’s high-side
side and low
low-side circuit breakers. What testing must be done
for this system?
This system is made up of component
components that are all unmonitored.. Assuming a time-based
time
Protection System Maintenance
aintenance Program schedule (as opposed to a Performance-Based
Performance
maintenance program), each component must be maintained per the most frequent
frequen hands-on
activities listed in the Tables.
5.2 Extending Time-Based
Based Maintenance
All maintenance is fundamentally time
time-based. Default time-based
based intervals are commonly
established to assure proper functioning of each component of the Protection
ection System, when
data on the reliability of the component
componentss is not available other than observations from timetime
based maintenance. The following factors may influence the established default intervals:
•
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self
self-monitoring
monitoring device), then the intervals may be extended,
extended or
manual testing may be eliminated. This is referred to as condition
condition-based
based maintenance
or CBM. CBM is valid only for precisely the componentss subject to monitoring. In the
case of microprocessor
microprocessor-based relays, self-monitoring
monitoring may not include automated
diagnostics of every component within a microprocessor.
PRC-005-33 Supplementary Reference and FAQ – AprilJuly 2013
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•
Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance-Based Maintenance, or
PBM. It is also sometimes referred to as reliability-centered maintenance, or RCM; but
PBM is used in this document.
•
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor-based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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6. Condition-Based Maintenance (CBM) Programs
Condition-based maintenance is the process of gathering and monitoring the information
available from modern microprocessor-based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self-monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non-invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
19
provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1-4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device-level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1-4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1-4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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7. Time-Based Versus Condition-Based
Maintenance
Time-based and condition-based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time-based and condition-based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06-16-000) on Mandatory Reliability Standards
for the Bulk-Power System, directed NERC to submit a modification to PRC-005-1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC-005-3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition-based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous - the time interval between verifications is
minutes or seconds. Thus, technically sound, condition-based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time-based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on-site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC-005-3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year - January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four-month
inspection was performed in January is due in May, but if performed in March (instead of May)
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with an internal alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
•
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented Lead-Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
•
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1-5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
•
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
•
A vented lead-acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
• A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
•
A microprocessor relay with alarm connected to SCADA to alert 24-hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
•
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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•
Vented Lead-Acid battery without any alarms connected to SCADA
(unmonitored)
•
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell-to-cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock-out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1-5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition-Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
This response may include tripping, closing, or other control actions.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
26
8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely - for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters - this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1-1 through 1-5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications-assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub-systems of a Protection System that need to be verified are shown.
Non-distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non-distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co-located non-BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC-005-3:
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
27
•
First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1-1 is for protective relays,
o Table 1-2 is for the associated communications systems,
o Table 1-3 is for current and voltage sensing devices,
o Table 1-4 is for station dc supply and
o Table 1-5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make-up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
•
Next look within that table for your device and its degree of monitoring. The Tables
have different hands-on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
•
This Maintenance activity is the minimum maintenance activity that must be
documented.
•
If your Performance-Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
•
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands-on maintenance activity cycles of
this component.
•
If your Performance-Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
•
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands-on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
•
An entity does not have to utilize the extended time intervals made available by this use
of condition-based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance manhours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
28
maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC-005-3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC-005-3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance-Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead-acid,
valve-regulated lead-acid, and nickel-cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC-005-3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC-005-3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
29
properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End-to-end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications-assisted trip scheme. While
this can be interpreted as a GPS-type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally-test the dc control circuitry. A documented Real-time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real-time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1-8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology- and method-neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor- based relays.
For relay maintenance departments that choose to test microprocessor-based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor- based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time-overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end-to-end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real-time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not-to-exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four-month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time-based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance-Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
•
Fault protective functions, including distance functions, voltage-restrained overcurrent
functions, or voltage-controlled overcurrent functions
•
Loss-of-field relays
•
Volts-per-hertz relays
•
Negative sequence overcurrent relays
•
Over voltage and under voltage protection relays
•
Stator-ground relays
•
Communications-based Protection Systems such as transfer-trip systems
•
Generator differential relays
•
Reverse power relays
•
Frequency relays
•
Out-of-step relays
•
Inadvertent energization protection
•
Breaker failure protection
For generator step-up, generator-connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
•
Transformer differential relays
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•
Neutral overcurrent relay
•
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal-conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system-connected station service transformers be included in
the Applicability. The generator-connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock-out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
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distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non-distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non-distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC-005-1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three-year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC-005-3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on-site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance-Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance-time-intervalclock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time-interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
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The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long-range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC-005-3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged-Fault-tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be reverified within an ongoing maintenance program. Example – it is not necessary to re-verify
correct terminal strip wiring on an ongoing basis.
PRC-005-3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC-005-3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC-005-3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
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It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non-compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in-service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in-service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1-1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto-generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built-in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I-17 (Transmission Relay System
Performance Comparison). Review of the I-17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
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To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively-known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self-testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1-1 through 1-5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10-year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self-monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
•
Relay Unavailability - the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
•
Abnormal Unavailability - the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self-monitoring capability is ST (for self test).
ST = 0 if there is no self-monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time-interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “timeinterval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time-interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six-year interval for the
electromechanical relay, instead of the five-year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10-year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
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facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance-Based Maintenance process may be used to
establish maintenance intervals (PRC-005 Attachment A Criteria for a Performance-Based
Protection System Maintenance Program). A Performance-Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance-Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance-Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance-Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance-Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001-2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance-Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro-mechanical lock-out relays;
likewise, one segment cannot be comprised of 60 GE lock-out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation σ, the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics - Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis - Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
Β=z
π(1 − π)
n
Where:
Β = bound on the error of distribution (allowable error)
z = standard error
π = expected failure rate
n = sample size required
Solving for n provides:
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
42
z
n = π(1 − π )
Β
2
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
π = 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
π = 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance-Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance-Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1-1 through 1-5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4%Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
43
The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
to the requirements of the Standard. The requirements established for Performance-Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power-plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance-Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance-Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance-Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in-service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re-calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
44
errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human-error is not pertinent data might be in the area of testing “86” lock-out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial sixyear interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human-error caused tripping
incidents. In this example the human-error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal-performing segments in a Performance-Based Maintenance system. Some examples are
listed below.
•
The maximum allowable interval, as established by the Performance-Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
•
Identifiable sub-groups of components within the established segment, which have
been identified to be the mal-performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance-Based Maintenance program in
order to remain within the program.
•
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal-performance.
•
components within the mal-performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal-performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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If you perform maintenance on a Protection System component for any reason (including as
part of a PRC-004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance-Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance-Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock-reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1-1-11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6-1-12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock-reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance-Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance-changing criteria.
Similarly, Functional Entities that want to establish a condition-based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands-on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1-4).
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE-HEA lock-out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
47
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six-year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V-insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper-sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
49
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real-time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
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Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested / year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Test
Total
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off-line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real-time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three-phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built-in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity-accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
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The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note - a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
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Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12-year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever-changing
test rate (units tested/year) may be un-workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20-year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to
# of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
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10. Overlapping the Verification of Sections of the
Protection System
Tables 1-1 through 1-5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
•
Time-based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1-1 through 1-5;
•
Monitoring as described in Tables 1-1 through 1-5;
•
A Performance-Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
•
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto-polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
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11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time-interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance-related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
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11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC-018-1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC-002-1 and PRC-018-1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single selfmonitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non-microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
•
One or more settings are changed for any reason.
•
A relay fails and is repaired or replaced with another unit.
•
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenanceactivity-time-interval-clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up-rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC-005-3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC-005-3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC-005-3 to remove
such component(s). Obviously, prudence would dictate that an “out-of-service” device is truly
made inactive. There are no record requirements listed in PRC-005-3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC-005-3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC-005-3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
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The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self-monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self-monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands-on
maintenance requirement), the manufacturers of the microprocessor-based self-monitoring
components in the Protection System should publish for the user a document or map that
shows:
•
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
•
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
•
Presenting or referencing the product manufacturer’s documents.
•
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
•
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
•
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
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13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology-neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early-generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC-005-3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non-electrical inputs are excluded.
Non-microprocessor based equipment is treated differently than microprocessor-based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
•
Non-microprocessor devices must be tested with voltage and/or current applied to the
device.
•
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber-optic Hall-effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
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protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
•
There is no specific ratio test, routine test or commissioning test mandated.
•
There is no specific documentation mandated.
•
It is required that the signal be present at the relay.
•
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
•
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
•
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
•
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real-time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
•
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
•
Another method for proving the voltage and/or current-sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
•
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current-sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all-inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
•
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
•
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
•
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
•
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
•
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi-meters, voltmeter, clamp-on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
•
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
•
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re-check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi-pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt-meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual-intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This sixyear tripping requirement can be completed as easily as tracking the Real-time Fault-clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit-interrupting device should not be confused with a motor-operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high-speed auto-closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred-tripping
device without the use of communications equipment. If this high-speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring-operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock-out relay
(86) that may exist in any particular trip scheme. If the lock-out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six-year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non-BES interrupting devices are not required. Normally-open contacts
that are not used to pass a trip signal and normally-closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC-005-2, other alarming relay control circuits,
(i.e., SF-6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard-wired trip circuitry with other methods of trip-signal conveyance
such as fiber-optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber-optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC-005-3 testing requirements because the SDT is
unaware of industry-recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently-approved PRC-005-1b, consistent with the SAR for Project 200717, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC-005-3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC-005-3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1-5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC-005-3 includes high-speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non-BES circuit breaker that is tripped via a Protection
System to which PRC-005-3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non-black-start) radial Loads but has a trip that originates from an under-frequency
(81) relay.
•
The relay must be verified.
•
The voltage signal to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non-BES breaker that is tripped via a Protection
System to which PRC-005-3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non-black-start) radial Loads but has a trip that originates from a BES 115KV
line relay.
•
•
•
•
•
•
•
•
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock-out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock-out (86) (or auxiliary (94)) relay and the
non-BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non-BES breaker does not have to be proven with an electrical trip.
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non-BES circuit breaker that is tripped via a
Protection System to which PRC-005-3 applies, such as the generator field breaker and low-side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non-BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
•
The differential relay must be verified.
•
The current signals to the relay must be verified.
•
All of the relevant dc supply tests still apply.
•
The unmonitored trip circuit between the relay and any lock-out or auxiliary relay must
be verified every 12 years.
•
The unmonitored trip circuit between the lock-out (or auxiliary relay) and the non-BES
breaker does not have to be proven with an electrical trip.
•
In the case where there is no lock-out or auxiliary tripping relay used, the trip circuit to
the non-BES breaker does not have to be proven with an electrical trip.
•
The trip coil of the non-BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally-closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
•
Protective relays which respond to electrical quantities,
•
Communications Systems necessary for correct operation of protective functions,
•
Voltage and current sensing devices providing inputs to protective relays,
•
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non-battery-based dc supply), and
•
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1-4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance-Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance-changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC-005-3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger - The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery - Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1-4.
Emerging Technologies - Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1-4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1-4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
•
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor-based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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72
•
Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one- to twosecond delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
•
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp-range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
•
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc-supplied equipment in the station should be considered before using this
approach.
•
Manufacturers of microprocessor-controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
•
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
•
Internal ohmic measurements of the cells and units of lead-acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
•
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1-4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve-regulated lead-acid, vented
lead-acid, or nickel-cadmium) and the maintenance activity chosen.
For example, if you have a valve-regulated lead-acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the sixmonth interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead-acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six-months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve-regulated lead-acid (VRLA) batteries and vented lead-acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer-supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead-acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel-cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve-regulated lead-acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1-4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell-to-cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1-4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1-4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell-to-cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1-4 by a Performance-Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1-4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1-4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot-checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally-accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel-cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel-cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel-cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel-cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel-cadmium batteries,
there are no significantly measurable properties of the nickel-cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1-4(c)
(Protection System Station dc supply Using nickel-cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check-off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check-off per battery bank is sufficient for documentation, as long as the single checkoff attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC-005-3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve-Regulated Lead-Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead-Acid (VLA)
batteries were unable to be used on this new type of lead-acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188-2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1-4. In cases where individual cells in a multi-cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1-4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead-acid (VLA) and nickel-cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1-4. Because
the electrolyte level in valve-regulated lead-acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1-4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved-quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve-regulated lead-acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1-4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead-acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry-out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1-4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six-month test” at Row 4 on Table 1-4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1-4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six-month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline - others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six-month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1-4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous selfmonitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1-4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1-4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1-4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1-4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1-4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1-4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1-4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications-assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications-assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communicationsassisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber-optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on-site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
•
On-off power-line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check-back test from one terminal.
•
Systems which use frequency-shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss-of-guard indication or alarm. For frequency-shift power-line carrier systems, the
guard signal level meter can also be checked.
•
Hard-wired pilot wire line Protection Systems typically have pilot-wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
•
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
•
On-off power-line carrier systems can be shown to be operational by automated
periodic power-line carrier check-back tests with remote alarming of failures.
•
Systems which use a frequency-shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss-of-guard alarm or low signal level alarm.
•
Hard-wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot-wire monitoring relays.
•
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
•
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
•
In many communications systems signal quality measurements, including signal-to-noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
•
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four-month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
•
Power Line Carrier (PLC) - The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
•
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
•
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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•
Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical-electrical signal format converters are the associated
communications equipment
Figure 1-2, A-1 and A-2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
•
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
•
An on-off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check-back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
•
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
•
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre-determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1-1 through 1-5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto-polling system; the only
requirement is that the alarm be brought to the action-site within 24 hours. This effectively
makes manned-stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned-station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non-mannedstation, which is that if the monitored point has an alarm that is auto-reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail-safe “form-b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1-1. Voltage and current-sensing devices have the same maintenance activity and
interval as Table 1-3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
•
Verify the trip path between the relay and lock-out and/or auxiliary tripping device(s).
•
Verify operation of any lock-out and/or auxiliary tripping device(s) used in the trip
circuit.
•
No verification of trip path required between the lock-out (and/or auxiliary tripping
device) and the non-BES interrupting device.
•
No verification of trip path required between the relay and trip coil for circuits that have
no lock-out and/or auxiliary tripping device(s).
•
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non-BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load-Shed relay and lock-out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock-out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under-frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non-BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock-out relay. While many failures of these distributed system circuit breakers (or
non-BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non-BES device, such as a battery bank that serves both a BES circuit breaker and a non-BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during underfrequency or under-voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load-generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC-005-3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC-005-3.
15.8.1 Frequently-asked Questions
Automatic Reclosing is a control, not a protective function; why then is Automatic
Reclosing maintenance included in the Protection System Maintenance Program
(PSMP)?
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes (separates) the Automatic Reclosing
from the Protection System. Automatic Reclosing is included in the PSMP because it is a more
pragmatic approach as compared to creating a parallel and essentially identical ‘Control System
Maintenance Program’ for the two Automatic Reclosing component types.
Our maintenance practice consists of initiating the Automatic Reclosing relay and
confirming the breaker closes properly and the close signal is released. This practice
verifies the control circuitry associated with Automatic Reclosing. Do you agree?”
The described task partially verifies the control circuit maintenance activity. To meet the
control circuit maintenance activity, responsible entities need to verify, upon initiation, that the
reclosing relay does not issue a premature closing command. As noted on page 12 of the
SAMS/SPCS report, the concern being addressed within the standard is premature
autoreclosing that has the potential to cause generating unit or plant instability. Reclosing
applications have many variations, responsible entities will need to verify the applicability of
associated supervisor/conditional logic and the reclosing relay operation; then verify the
conditional logic or that the reclosing relay performs in a manner that does not result in a
premature closing command being issued.
Some examples of conditions which can result in a premature closing command are: an
improper supervision or conditional logic input which provides a false state and allows the
reclosing relay to issue an improper close command based on incorrect conditions (i.e. voltage
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
92
supervision, equipment status, sync window verification); timers utilized for closing actuation
or reclosing arming/disarming circuitry which could allow the reclosing relay to issue an
improper close command; a reclosing relay output contact failure which could result in a madeup-close condition / failure-to-release condition.
Why was a close-in three phase fault present for twice the normal clearing time
chosen for the Automatic Reclosing exclusion? It exceeds TPL requirements and
ignores the breaker closing time in a trip-close-trip sequence, thus making the
exclusion harder to attain.
This condition represents a situation where a close signal is issued with no time delay or with
less time delay than is intended, such as if a reclosing contact is welded closed. This failure
mode can result in a minimum trip-close-trip sequence with the two faults cleared in primary
protection operating time, and the open time between faults equal to the breaker closing cycle
time. The sequence for this failure mode results in system impact equivalent to a high-speed
autoreclosing sequence with no delay added in the autoreclosing logic. It represents a failure
mode which must be avoided because it exceeds TPL requirements.
Do we have to test the various breaker closing circuit interlocks and controls such
as anti-pump?
These components are not specifically addressed within Table 4, and need not be individually
tested. They are indirectly verified by performing the Automatic Reclosing control circuitry
verification as established in Table 4.
None
For Automatic Reclosing that is not part of an SPS, do we have to close the circuit
breaker periodically?
No. For this application, you need only to verify that the Automatic Reclosing, upon initiation,
does not issue a premature closing command. This activity is concerned only with assuring that
a premature close does not occur, and cause generating plant instability.
For Automatic Reclosing that is part of an SPS, do we have to close the circuit
breaker periodically?
Yes. In this application, successful closing is a necessary portion of the SPS, and must be
verified.
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team
recognizes that there are concurrent evidence requirements of other NERC standards that
could, at times, fulfill evidence requirements of this Standardstandard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
• Process documents or plans
• Data (such as relay settings sheets, photos, SCADA, and test records)
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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•
•
•
•
•
•
•
•
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check-off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC-016 could work for the activity tracking requirements
under this PRC-005-3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor-Based
Transmission-Line Protective Relays, Part I - Explanation of the Statistics, and Part II Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016-6
PWRD and 96WM 127-1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR- 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of ValveRegulated Lead-Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead-Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45-2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented LeadAcid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR-100248, 1006757, August 2002.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
95
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” - Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
19. “Considerations for Maintenance and Testing of Autoreclosing Schemes,” NERC
System Analysis and Modeling Subcommittee and NERC System Protection and
Control Subcommittee, November 2012
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC-005-2, and also
may not be all-inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
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Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Component of
Protection System
Includes
Excludes
Devices that use non-electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync-check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber-optic systems that
carry a trip signal as well as hardwired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
4
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
5
Communications
systems necessary
for correct operation
of protective
functions
Tele-protection equipment used
to convey specific information, in
the form of analog or digital
signals, necessary for the correct
operation of protective functions.
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
Additional information can be found in References
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Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A-1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two-terminal pilot protection scheme to protect for line Faults, and to avoid overtripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self-monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self-monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on-off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check-back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A-2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
PRC-005-3 Supplementary Reference and FAQ – AprilJuly 2013
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contacts of a small telephone-type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check-back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone-type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally-occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC-005-3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front-panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay-carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
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Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Al McMeekin
NERC
Merle Ashton
Tri-State G&T
Michael Palusso
Southern California Edison
Bob Bentert
Florida Power & Light Company
Mark Peterson
Great River Energy
Forrest Brock
Western Farmers Electric Cooperative
John Schecter
American Electric Power
Aaron Feathers
Pacific Gas and Electric Company
William D. Shultz
Southern Company Generation
Sam Francis
Oncor Electric Delivery
Eric A. Udren
Quanta Technology
Carol Gerou
Midwest Reliability Organization
Scott Vaughan
City of Roseville Electric Department
Russell C. Hardison
Tennessee Valley Authority
Matthew Westrich
American Transmission Company
David Harper
NRG Texas Maintenance Services
Philip B. Winston
Southern Company Transmission
James M. Kinney
FirstEnergy Corporation
David Youngblood
Luminant Power
Mark Lucas
ComEd
John A. Zipp
ITC Holdings
Kristina Marriott
ENOSERV
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103
Table of Issues and Directives
Project 2007-17.2 PRC-005-3
Protection System and Automatic Reclosing Maintenance
Table of Issues and Directives Associated with PRC-005-3
Source
FERC Order
758
Directive Language
(including pg #)
27. We note that the original project to revise
Reliability Standard PRC-005 failed a recirculation
ballot in July of 2011. The project was
subsequently reinitiated to continue the efforts
to develop Reliability Standard PRC-005-2. Given
that the project to draft proposed revisions to
Reliability Standard PRC-005-1 continues in this
reinitiated effort, and the importance of
maintaining and testing reclosing relays, we
direct NERC to include maintenance and testing
of reclosing relays that can affect the reliable
operation of the Bulk-Power System, as discussed
above, within these reinitiated efforts to revise
Reliability Standard PRC-005.
Disposition
Specific minimum activities and maximum
allowable intervals are included in the draft
standard within Table 4.
Section and/or
Requirement(s)
Applicability 4.2.6
Requirement R1, R3,
Requirement R4, Table 4
Standards Announcement
Project 2007-17.2 Protection System Maintenance and Testing
Phase 2 (Reclosing Relays) PRC-005-3
Ballot and Non-Binding Poll now open through August 23, 2013
Now Available
A ballot for PRC-005-3 – Protection System and Automatic Reclosing Maintenance and non-binding
poll of the associated Violation Risk Factors and Violation Severity Levels is open through 8 p.m.
Eastern on Friday, August 23, 2013.
Background information for this project can be found on the project page.
Instructions
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual, which
requires all negative votes to have an associated comment submitted (or an indication of support
of another entity’s comments). Please see NERC’s announcement regarding the balloting software
updates and the guidance document, which explains how to cast your ballot and note if you’ve
made a comment in the online comment form or support another entity’s comment.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard. If
the comments do not show the need for significant revisions, the standard will proceed to a final ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-17.2 PSMT Phase 2 (Reclosing Relays)
2
Standards Announcement
Project 2007-17.2 Protection System Maintenance and Testing
Phase 2 (Reclosing Relays) PRC-005-3
Formal Comment Period: July 10, 2013 – August 23, 2013
Ballot Pools Forming Now: July 10, 2013 – August 8, 2013
Upcoming:
Ballot and Non-Binding Poll: August 14-23, 2013
Now Available
A 45-day formal comment period for PRC-005-3 – Protection System and Automatic Reclosing
Maintenance is open through 8 p.m. Eastern on Friday, August 23, 2013. A ballot pool is being
formed and the ballot pool window is open through 8 a.m. Eastern on Thursday, August 8, 2013
(please note that ballot pools close at 8 a.m. Eastern and mark your calendar accordingly).
Background information for this project can be found on the project page.
Instructions for Joining Ballot Pool(s)
Ballots pools are being formed for PRC-005-3 – Protection System and Automatic Reclosing
Maintenance and the associated non-binding polls in this project. Registered Ballot Body members
must join the ballot pools to be eligible to vote in the balloting and submittal of an opinion for the
non-binding polls of the associated VRFs and VSLs. Registered Ballot Body members may join the
ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for this project are:
Ballot: [email protected]
Non-Binding poll: [email protected]
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Friday, August 23, 2013. Please use the
electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Wendy Muller. An off-line, unofficial copy of the comment forms are posted on the
project page.
Next Steps
A ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and Violation Severity
Levels (VSLs) will be conducted as previously outlined.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-17.2 PSMT Phase 2 (Reclosing Relays) – July 2013
2
Standards Announcement
Project 2007-17.2 Protection System Maintenance and Testing
Phase 2 (Reclosing Relays) PRC-005-3
Ballot and Non-Binding Poll Results
Now Available
A ballot for PRC-005-3 – Protection System and Automatic Reclosing Maintenance and non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) concluded at 8
p.m. Eastern on Friday, August 23, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results
for the ballot.
Approval
Non-binding Poll Results
Quorum: 78.33%
Quorum: 77.45%
Approval: 79.24%
Supportive Opinions: 81.37%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if needed,
make revisions to the standard. If the comments do not show the need for significant revisions, the
standard will proceed to a final ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-17.2 PRC-005-3 August 2013
Password
Ballot Period: 8/14/2013 - 8/26/2013
Log in
Ballot Type: Initial
Total # Votes: 318
Register
Total Ballot Pool: 406
Quorum: 78.33 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
79.24 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
107
1
59
0.776
17
0.224
0
8
23
9
0.4
3
0.3
1
0.1
0
3
2
95
1
49
0.71
20
0.29
0
5
21
33
1
19
0.905
2
0.095
0
2
10
92
1
47
0.701
20
0.299
0
6
19
53
1
31
0.738
11
0.262
0
3
8
0
0
0
0
0
0
0
0
0
6
0.2
2
0.2
0
0
0
0
4
2
0.1
1
0.1
0
0
0
0
1
9
0.9
8
0.8
1
0.1
0
0
0
406
6.6
219
5.23
72
1.37
0
27
88
Individual Ballot Pool Results
Ballot
Segment
1
1
Organization
Member
Ameren Services
American Electric Power
Eric Scott
Paul B Johnson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
Affirmative
Negative
NERC
Notes
SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz
-American
Electric Power)
NERC Standards
1
American Transmission Company, LLC
Andrew Z Pusztai
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Robert Smith
John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
David Rudolph
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Kevin J Lyons
Joseph Turano Jr.
Abstain
Affirmative
Chang G Choi
Affirmative
1
1
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Basin Electric Power Cooperative
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Iowa Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Daniel S Langston
Jack Stamper
Affirmative
Affirmative
1
Cleco Power LLC
Danny McDaniel
1
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Oliver A Burke
William J Smith
1
1
Florida Keys Electric Cooperative Assoc.
Dennis Minton
1
1
1
1
1
1
1
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
JEA
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
1
1
1
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)4/5/13 5/6/13
Comment
Period - (FMPA)
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Negative
Jim D Cyrulewski
Ted Hobson
Affirmative
Affirmative
1
KAMO Electric Cooperative
Walter Kenyon
1
Kansas City Power & Light Co.
Jennifer Flandermeyer
1
1
1
1
1
1
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Affirmative
Affirmative
1
Manitoba Hydro
Nazra S Gladu
Negative
1
1
1
1
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
COMMENT
RECEIVED
Affirmative
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC Standards
1
1
1
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
Mark Ramsey
Michael Jones
Cole C Brodine
1
1
1
1
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
1
Oklahoma Gas and Electric Co.
Terri Pyle
1
1
1
1
1
1
1
1
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
1
Potomac Electric Power Co.
David Thorne
1
1
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Brenda L Truhe
Laurie Williams
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool
(SPP))
Randy MacDonald
Bruce Metruck
Affirmative
Kevin White
Affirmative
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Affirmative
Affirmative
Abstain
Kenneth D. Brown
Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke PSEG)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
1
1
1
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
1
Tri-State G & T Association, Inc.
Tracy Sliman
1
Tucson Electric Power Co.
John Tolo
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (ACES
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
NERC Standards
1
1
1
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Affirmative
Affirmative
Affirmative
1
Western Area Power Administration
Lloyd A Linke
Negative
1
Xcel Energy, Inc.
Gregory L Pieper
Negative
2
BC Hydro
2
Electric Reliability Council of Texas, Inc.
Venkataramakrishnan
Vinnakota
Cheryl Moseley
2
Independent Electricity System Operator
Barbara Constantinescu
2
2
2
2
2
2
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Abstain
Affirmative
Affirmative
3
AEP
Michael E Deloach
Negative
3
Alabama Power Company
Robert S Moore
Negative
3
3
3
Ameren Services
American Public Power Association
Associated Electric Cooperative, Inc.
Mark Peters
Nathan Mitchell
Chris W Bolick
Affirmative
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz)
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
3
Atlantic City Electric Company
NICOLE BUCKMAN
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Redding
City of Tallahassee
City of Vineland
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
Adam M Weber
Thomas C Duffy
Dennis M Schmidt
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Bill Hughes
Bill R Fowler
Kathy Caignon
Affirmative
Affirmative
3
Cleco Corporation
Michelle A Corley
Negative
3
3
3
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Charles Morgan
John Bee
Peter T Yost
3
Consumers Energy Company
Gerald G Farringer
3
CPS Energy
Jose Escamilla
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc &
Affiliates)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc &
Affiliates)
3
Delmarva Power & Light Co.
Michael R. Mayer
Negative
3
Detroit Edison Company
Kent Kujala
Abstain
3
Dominion Resources, Inc.
Connie B Lowe
Negative
3
Entergy
Joel T Plessinger
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel)
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
NERC Standards
3
3
3
3
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power & Light Co.
Florida Power Corporation
Cindy E Stewart
Joe McKinney
Summer C Esquerre
Lee Schuster
Affirmative
Affirmative
Affirmative
3
Georgia Power Company
Danny Lindsey
Negative
3
3
Georgia System Operations Corporation
Great River Energy
Scott McGough
Brian Glover
Affirmative
Affirmative
3
Gulf Power Company
Paul C Caldwell
3
3
3
3
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
3
Kansas City Power & Light Co.
Charles Locke
3
3
Kissimmee Utility Authority
Lakeland Electric
Gregory D Woessner
Mace D Hunter
3
Lincoln Electric System
Jason Fortik
3
3
3
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Mike Anctil
Charles A. Freibert
Stephen D Pogue
3
Manitoba Hydro
Greg C. Parent
3
3
3
Manitowoc Public Utilities
MEAG Power
MidAmerican Energy Co.
Thomas E Reed
Roger Brand
Thomas C. Mielnik
3
Mississippi Power
Jeff Franklin
3
Modesto Irrigation District
Jack W Savage
3
Muscatine Power & Water
John S Bos
3
National Grid USA
Brian E Shanahan
3
Nebraska Public Power District
Tony Eddleman
3
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Ocala Electric Utility
David R Rivera
3
3
3
3
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Negative
Affirmative
Affirmative
Affirmative
3
3
3
3
3
3
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Affirmative
Affirmative
Ramon J Barany
David McDowell
David Anderson
Donald Hargrove
SUPPORTS
THIRD PARTY
COMMENTS (SPP-Robert
Rhodes)
Affirmative
Affirmative
Oklahoma Gas and Electric Co.
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Affirmative
Skyler Wiegmann
3
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool
(SPP))
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)
NERC Standards
3
3
3
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Terry L Baker
Michael Mertz
Thomas G Ward
Abstain
Abstain
3
Potomac Electric Power Co.
Mark Yerger
Negative
3
Public Service Electric and Gas Co.
Jeffrey Mueller
Negative
3
3
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Erin Apperson
Eddy Reece
3
Rutherford EMC
Thomas M Haire
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
3
Xcel Energy, Inc.
Michael Ibold
4
4
4
4
4
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
Buckeye Power, Inc.
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Kenneth Goldsmith
Duane S Dahlquist
Manmohan K Sachdeva
Reza Ebrahimian
Kevin McCarthy
4
Consumers Energy Company
Tracy Goble
Negative
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Abstain
4
4
4
4
4
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Pepco
Holdings Inc &
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (John Seelke
on behalf of
PSEG
Companies)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy)
Abstain
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
Affirmative
Affirmative
Margaret Powell
Affirmative
Henry E. LuBean
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
4
4
4
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
4
South Mississippi Electric Power Association
Steven McElhaney
4
4
4
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
4
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Affirmative
Affirmative
Negative
5
AEP Service Corp.
Brock Ondayko
5
5
5
5
5
5
5
Sam Dwyer
Scott Takinen
Brent R Carr
Matthew Pacobit
Steve Wenke
Clement Ma
George Tatar
5
Amerenue
Arizona Public Service Co.
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
5
Buckeye Power, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
5
Cleco Power
Stephanie Huffman
5
5
5
5
5
5
5
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
5
Dominion Resources, Inc.
Mike Garton
5
5
5
5
5
Duke Energy
Dynegy Inc.
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Dale Q Goodwine
Dan Roethemeyer
Gustavo Estrada
John R Cashin
Tracey Stubbs
5
Essential Power, LLC
Patrick Brown
5
5
5
5
5
5
5
Exelon Nuclear
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
5
5
Kansas City Power & Light Co.
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Thomas FoltzAmerican
Electric Power)
Affirmative
Abstain
Affirmative
Affirmative
Mike D Kukla
Francis J. Halpin
Brett Holland
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP _ Robert
Rhodes)
NERC Standards
5
Kissimmee Utility Authority
Mike Blough
Negative
5
Lakeland Electric
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Negative
5
5
5
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Kenneth Silver
Karin Schweitzer
Rick Terrill
5
Manitoba Hydro
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Neil D Hammer
Affirmative
Affirmative
Affirmative
5
5
5
Muscatine Power & Water
Mike Avesing
Negative
5
Nebraska Public Power District
Don Schmit
Negative
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
Affirmative
Abstain
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
Occidental Chemical
Michelle R DAntuono
Negative
5
Oglethorpe Power Corporation
Bernard Johnson
5
Oklahoma Gas and Electric Co.
Leo Staples
5
5
5
5
5
5
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
Mahmood Z. Safi
David Ramkalawan
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
Negative
Tim Kucey
Negative
5
Public Utility District No. 1 of Lewis County
Steven Grega
Negative
5
5
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS - (I
support
comments
submitted by
Oklahoma Gas
& Electric)
Abstain
Abstain
Affirmative
PSEG Fossil LLC
Public Utility District No. 2 of Grant County,
Michiko Sell
Washington
Puget Sound Energy, Inc.
Lynda Kupfer
Sacramento Municipal Utility District
Susan Gill-Zobitz
COMMENT
RECEIVED
Affirmative
Affirmative
5
5
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Affirmative
Affirmative
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
5
SUPPORTS
THIRD PARTY
COMMENTS 4/5/13 5/6/13
Comment
Period(Florida
Municipal
Power Agency)
- (Florida
Municipal
Power Agency)
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (PSEG
comments
submitted by
John Seelke)
SUPPORTS
THIRD PARTY
COMMENTS (Brown at
Essential
Power)
NERC Standards
5
5
5
5
5
5
5
5
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
5
Southern Company Generation
William D Shultz
Negative
5
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
5
5
5
5
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Utility System Effeciencies, Inc. (USE)
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Melissa Kurtz
Erika Doot
Robert L Dintelman
Bryan Taggart
Linda Horn
Scott E Johnson
5
Xcel Energy, Inc.
Liam Noailles
Negative
6
AEP Marketing
Edward P. Cox
Negative
6
6
6
6
6
6
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
6
Cleco Power LLC
Robert Hirchak
Negative
6
6
6
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Shannon Fair
David Balban
David J Carlson
Affirmative
Affirmative
6
Dominion Resources, Inc.
Louis S. Slade
6
6
6
6
6
6
6
6
Duke Energy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Greg Cecil
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
6
6
Los Angeles Department of Water & Power
Luminant Energy
Brad Packer
Brenda Hampton
6
Manitoba Hydro
Blair Mukanik
Negative
6
6
MidAmerican Energy Co.
Modesto Irrigation District
Dennis Kimm
James McFall
Affirmative
6
Muscatine Power & Water
John Stolley
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
American
Electric Power)
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
NERC Standards
6
6
6
6
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
NRG Energy, Inc.
Saul Rojas
Steve C Hill
Joseph O'Brien
Alan Johnson
6
Oklahoma Gas & Electric Services
Jerry Nottnagel
6
6
6
6
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
6
PSEG Energy Resources & Trade LLC
Peter Dolan
6
6
6
6
6
6
6
6
Public Utility District No. 1 of Chelan County Hugh A. Owen
Sacramento Municipal Utility District
Diane Enderby
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown
Seattle City Light
Dennis Sismaet
Seminole Electric Cooperative, Inc.
Trudy S. Novak
Snohomish County PUD No. 1
Kenn Backholm
Southern California Edison Company
Lujuanna Medina
6
Southern Company Generation and Energy
Marketing
John J. Ciza
6
6
6
6
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
6
Western Area Power Administration - UGP
Marketing
Peter H Kinney
6
Wisconsin Public Service Corp.
David Hathaway
6
Xcel Energy, Inc.
David F Lemmons
8
8
8
8
8
8
Edward C Stein
Merle Ashton
Roger C Zaklukiewicz
William R Harris
Frederick R Plett
Terry Volkmann
10
10
10
10
10
10
10
Foundation for Resilient Societies
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
10
Texas Reliability Entity, Inc.
Donald G Jones
10
Western Electricity Coordinating Council
9
9
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)
Negative
Affirmative
Abstain
Affirmative
COMMENT
RECEIVED
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
Negative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Lloyd Linke)
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel Energy)
Negative
Affirmative
Affirmative
Donald Nelson
Diane J. Barney
Affirmative
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Emily Pennel
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Steven L. Rueckert
Legal and Privacy
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
COMMENT
RECEIVED
Negative
Affirmative
NERC Standards
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=87ebd617-23bc-48e8-a63f-3ed05872e7e1[8/28/2013 10:11:25 AM]
Non-binding Poll
Project 2007-17.2
Non-binding Poll Results
Non-binding Poll
Project 2007-17.2 PRC-005-3 Non-binding Poll
Name:
Poll Period: 8/14/2013 - 8/26/2013
Total # Opinoins: 285
Total Ballot Pool: 368
77.45% of those who registered to participate provided an opinion or an
Ballot Results: abstention; 81.37% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern
California
Basin Electric Power Cooperative
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric,
LLC
Central Electric Power Cooperative
Central Iowa Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City of Tallahassee
Clark Public Utilities
1
Cleco Power LLC
1
Colorado Springs Utilities
1
1
1
1
1
1
1
1
1
1
1
1
1
Member
Eric Scott
Paul B Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
David Rudolph
Patricia Robertson
Donald S. Watkins
Opinions
NERC
Notes
Abstain
Abstain
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Tony Kroskey
John C Fontenot
John Brockhan
Abstain
Michael B Bax
Kevin J Lyons
Joseph Turano Jr.
Affirmative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Affirmative
Affirmative
Danny McDaniel
Paul Morland
Christopher L de
Consolidated Edison Co. of New York
Graffenried
CPS Energy
Richard Castrejana
Negative
Affirmative
Affirmative
COMMENT
RECEIVED
1
1
1
1
1
1
1
1
1
1
1
1
1
Dairyland Power Coop.
Dayton Power & Light Co.
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative
Assoc.
Robert W. Roddy
Hertzel Shamash
Douglas E. Hils
Oliver A Burke
William J Smith
Dennis Minton
Affirmative
Affirmative
Abstain
Affirmative
Negative
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
1
1
1
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
1
Kansas City Power & Light Co.
Jennifer Flandermeyer
1
1
1
Larry E Watt
Doug Bantam
Robert Ganley
1
1
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Martyn Turner
William Price
Affirmative
Affirmative
1
Manitoba Hydro
Nazra S Gladu
Negative
1
1
1
1
1
1
1
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine
1
1
1
1
1
1
1
Non-binding Poll – 2007-17.2
SUPPORTS
THIRD
PARTY
COMMENTS
(FMPA)From
4/5/13 5/6/13
Comment
Period
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Michael Moltane
Abstain
Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
John Burnett
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Randy MacDonald
Bruce Metruck
Affirmative
Kevin White
Affirmative
David Boguslawski
Julaine Dyke
Affirmative
Affirmative
2
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New
Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of
Okanogan County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service
Authority
Southern California Edison Company
John Canavan
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
Brenda L Truhe
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Laurie Williams
Abstain
Kenneth D. Brown
Abstain
Dale Dunckel
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Denise Stevens
Long T Duong
Tom Hanzlik
Affirmative
Affirmative
Affirmative
Shawn T Abrams
Affirmative
Steven Mavis
Affirmative
1
Southern Company Services, Inc.
1
Southwest Transmission Cooperative,
John Shaver
Inc.
Negative
1
Sunflower Electric Power Corporation Noman Lee Williams
Negative
1
1
1
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Beth Young
Howell D Scott
Steven Powell
1
Tri-State G & T Association, Inc.
Tracy Sliman
1
1
Tucson Electric Power Co.
U.S. Bureau of Reclamation
John Tolo
Richard T Jackson
Non-binding Poll – 2007-17.2
Robert A. Schaffeld
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
SUPPORTS
THIRD
PARTY
COMMENTS
- (ACES
Comments)
SUPPORTS
THIRD
PARTY
COMMENTS
- (ACES)
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
3
1
1
United Illuminating Co.
Westar Energy
Jonathan Appelbaum
Allen Klassen
1
Western Area Power Administration
Lloyd A Linke
2
BC Hydro
Venkataramakrishnan
Vinnakota
Abstain
Cheryl Moseley
Abstain
Barbara
Constantinescu
Affirmative
2
2
Electric Reliability Council of Texas,
Inc.
Independent Electricity System
Operator
2
Midwest ISO, Inc.
Marie Knox
2
New Brunswick System Operator
New York Independent System
Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alden Briggs
2
2
2
3
Affirmative
Affirmative
Negative
Negative
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Abstain
Abstain
Alabama Power Company
Robert S Moore
3
3
3
3
3
3
Mark Peters
Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
3
3
3
3
3
3
Ameren Services
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Anaheim Public Utilities
Department
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Redding
City of Tallahassee
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Bill Hughes
Bill R Fowler
Affirmative
3
Cleco Corporation
Michelle A Corley
Negative
3
3
Colorado Springs Utilities
Charles Morgan
Consolidated Edison Co. of New York Peter T Yost
3
Consumers Energy Company
Gerald G Farringer
3
3
CPS Energy
Detroit Edison Company
Jose Escamilla
Kent Kujala
Non-binding Poll – 2007-17.2
SUPPORTS
THIRD
PARTY
COMMENTS
- (MRO
NERC
Standards
Review
Forum)
Abstain
3
3
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Dennis M Schmidt
Affirmative
Affirmative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
4
3
3
3
3
3
3
3
3
3
Dominion Resources, Inc.
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power & Light Co.
Florida Power Corporation
Georgia Power Company
Georgia System Operations
Corporation
Great River Energy
Connie B Lowe
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Summer C Esquerre
Lee Schuster
Abstain
Affirmative
Affirmative
Affirmative
Danny Lindsey
Negative
Scott McGough
Affirmative
Brian Glover
Affirmative
3
Gulf Power Company
Paul C Caldwell
3
3
3
3
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Negative
Affirmative
Affirmative
Kansas City Power & Light Co.
Charles Locke
3
3
3
Gregory D Woessner
Mace D Hunter
Jason Fortik
Affirmative
Abstain
Mike Anctil
Affirmative
3
3
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Charles A. Freibert
Stephen D Pogue
Affirmative
3
Manitoba Hydro
Greg C. Parent
3
3
3
Manitowoc Public Utilities
MEAG Power
MidAmerican Energy Co.
Thomas E Reed
Roger Brand
Thomas C. Mielnik
3
Mississippi Power
Jeff Franklin
3
Modesto Irrigation District
Jack W Savage
3
Muscatine Power & Water
Non-binding Poll – 2007-17.2
John S Bos
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
Affirmative
3
3
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
Negative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (SPPRobert
Rhodes)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
5
- (MRO
NSRF)
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Brian E Shanahan
Tony Eddleman
David R Rivera
Affirmative
Abstain
Skyler Wiegmann
Affirmative
Ramon J Barany
David McDowell
Donald Hargrove
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Jeffrey Mueller
Erin Apperson
Eddy Reece
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
3
Rutherford EMC
Thomas M Haire
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
James Leigh-Kendall
John T. Underhill
James M Poston
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
Michael Ibold
Kenneth Goldsmith
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
4
4
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
4
Consumers Energy Company
Tracy Goble
4
Non-binding Poll – 2007-17.2
Affirmative
Abstain
Abstain
Abstain
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (Duke
Energy)
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
6
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations
Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of
Snohomish County
Sacramento Municipal Utility District
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Arkansas Electric Cooperative
Corporation
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba
Lucky peak power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of
Springfield
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Affirmative
Guy Andrews
Affirmative
Herb Schrayshuen
Bob C. Thomas
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Mark Ringhausen
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Henry E. LuBean
John D Martinsen
Affirmative
Mike Ramirez
Steven R Wallace
Abstain
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Affirmative
Abstain
Abstain
Abstain
Abstain
Brent R Carr
Matthew Pacobit
Steve Wenke
Clement Ma
George Tatar
Abstain
Affirmative
Mike D Kukla
Francis J. Halpin
Shari Heino
Affirmative
Negative
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Affirmative
Steve Rose
Affirmative
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy Power
Mike D Hirst
Non-binding Poll – 2007-17.2
Abstain
SUPPORTS
THIRD
PARTY
COMMENTS
- (ACES)
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
7
5
5
5
5
5
5
5
5
5
5
5
5
Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Gustavo Estrada
John R Cashin
Tracey Stubbs
5
Essential Power, LLC
Patrick Brown
5
5
5
5
5
5
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
5
Kansas City Power & Light Co.
Brett Holland
5
5
Kissimmee Utility Authority
Lakeland Electric
Mike Blough
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
5
Dennis Florom
Abstain
Kenneth Silver
Affirmative
5
5
Lincoln Electric System
Los Angeles Department of Water &
Power
Lower Colorado River Authority
Luminant Generation Company LLC
Karin Schweitzer
Rick Terrill
Affirmative
Affirmative
5
Manitoba Hydro
S N Fernando
Negative
David Gordon
Abstain
5
5
5
5
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Steven Grego
Neil D Hammer
5
Muscatine Power & Water
Mike Avesing
5
5
5
5
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
Non-binding Poll – 2007-17.2
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (SPP Robert
Rhodes)
Abstain
Abstain
Negative
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (MRO
NSRF)
SUPPORTS
8
Corp.
5
Occidental Chemical
Michelle R DAntuono
5
5
5
5
5
5
5
5
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Bernard Johnson
Leo Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
Tim Kucey
5
5
5
5
5
5
5
5
5
5
5
5
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
Steven Grega
Negative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
Negative
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Southern Company Generation
William D Shultz
Negative
5
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Utility System Effeciencies, Inc.
(USE)
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Melissa Kurtz
Erika Doot
Affirmative
Affirmative
Robert L Dintelman
Affirmative
Scott E Johnson
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Affirmative
5
5
6
6
6
Non-binding Poll – 2007-17.2
SUPPORTS
THIRD
PARTY
COMMENTS
- (essential
power)
Michiko Sell
5
5
THIRD
PARTY
COMMENTS
- (ACES)
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
- (Southern
Company)
Abstain
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Abstain
Abstain
9
6
6
6
6
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
6
Cleco Power LLC
Robert Hirchak
6
6
6
6
6
6
6
6
6
6
6
Shannon Fair
David Balban
Greg Cecil
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Brad Packer
Affirmative
6
Colorado Springs Utilities
Con Edison Company of New York
Duke Energy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Brenda Hampton
Affirmative
6
Manitoba Hydro
Blair Mukanik
Negative
6
6
MidAmerican Energy Co.
Modesto Irrigation District
Dennis Kimm
James McFall
Affirmative
6
6
Muscatine Power & Water
John Stolley
6
6
6
6
6
6
6
6
6
6
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
NRG Energy, Inc.
Oklahoma Gas & Electric Services
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Saul Rojas
Steve C Hill
Joseph O'Brien
Alan Johnson
Jerry Nottnagel
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
6
6
6
6
6
6
6
6
6
Southern Company Generation and
Energy Marketing
Non-binding Poll – 2007-17.2
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina
John J. Ciza
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
- (MRO
NSRF)
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
10
COMMENTS
- (Southern
Company)
6
6
6
6
6
8
8
8
8
9
10
10
10
10
10
10
10
10
10
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Western Area Power Administration Peter H Kinney
UGP Marketing
Edward C Stein
Roger C Zaklukiewicz
Frederick R Plett
Terry Volkmann
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Donald Nelson
Department of Public Utilities
Florida Reliability Coordinating
Linda Campbell
Council
Midwest Reliability Organization
Russel Mountjoy
New York State Reliability Council
Alan Adamson
Northeast Power Coordinating Council Guy V. Zito
ReliabilityFirst Corporation
Anthony E Jablonski
SERC Reliability Corporation
Joseph W Spencer
Southwest Power Pool RE
Emily Pennel
Texas Reliability Entity, Inc.
Donald G Jones
Western Electricity Coordinating
Steven L. Rueckert
Council
Non-binding Poll – 2007-17.2
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
- (Lloyd
Linke)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
11
Individual or group. (41 Responses)
Name (25 Responses)
Organization (25 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (6 Responses)
Comments (41 Responses)
Question 1 (35 Responses)
Question 1 Comments (35 Responses)
Question 2 (31 Responses)
Question 2 Comments (35 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Yes
Yes
Referencing Applicability Section 4.2.6, the Balancing Authority has to notify and provide
documentation to the appropriate entities in 4.2.6.1 and 4.2.6.2 that automatic reclosing
maintenance is required. TO substations within 10 circuit miles will need to be identified by
the Balancing Authority as well. To clarify Footnote 1 on page 4, suggest the following
rewording: Automatic Reclosing as addressed in Sections 4.2.6.1 and 4.2.6.2 may be excluded
if the equipment owner can demonstrate that a close in three-phase fault not cleared for the
length of a breaker trip-close-trip operating time does not result in a total loss of gross
generation in the Interconnection exceeding the gross capacity of the largest BES generating
unit within the Balancing Authority Area where the Automatic Reclosing is applied. In the
Implementation Plan the SDT did a good job inserting the appropriate wording to remove a
potential conflict with regulatory practice with respect to the effective date of the standard.
However, the wording needs to be inserted in Section 4 of the Background Section. Review
the Implementation Plan and insert the following words where appropriate: “, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.” The
Implementation Plan must be made available throughout the life of the Standard.
Group
Duke Energy
Colby Bellville
Yes
Duke Energy requests additional information regarding the Footnote 1 exclusion provision. As
written, it is unclear as to what exactly is needed to provide demonstration for this provision,
as well as the frequency of the demonstration necessary to remain compliant. For example, if
an entity performs an analysis to prove that the exclusion was applicable to a specific
Automatic Reclosing Relay, would the entity need to run another analysis ever again, or would
an analysis only need to be done if there was a change to the Balancing Authority Area’s
system or the BES? Also, Duke Energy suggests that because Footnote 1 effectively acts as an
exclusion, that the SDT consider placing the Footnote in the standard itself.
Yes
Duke Energy requests clarification from the SDT as to whom they envision identifying the
newly acquired Automatic Reclosing Components, how they must identify, and what
documentation is needed to show correspondence with an entity’s maintenance program.
Also, Duke Energy suggests that the SDT consider placing the Implementation Plan for Newly
identified Automatic Reclosing Components in the standard itself, and not as its own
document.
Group
MRO NERC Standards Review Forum (NSRF)
Russel Mountjoy
No
Plase clarify what is meant by “BES elements at substations one bus away from generating
plants”. How is the one bus criterion applied at a generating station with power
transformation and multiple voltages? The use of the words substation and “one bus away”
leaves the definition open to interpretation when a plant is connected at one voltage class
and there are reclosing relays at another voltage class. The higher or lower voltage class bus
could be read as “one bus away” and yet at the same substation. It may be necessary to speak
in terms of either substations or electrical busses. It may also be necessary to define how a
different voltage class bus should be treated. Could a large power transformer between
voltage classes be equivalent to 10 circuit miles of impedance? Was the reclosing only meant
to apply at the same voltage class?
No
The implementation plan should be based upon the existing maintenance schedules for the
affected BES components.
Individual
Thomas Foltz
American Electric Power
No
Regarding 4.2.6.2 in the Facilities section, the verbiage used suggests that substations that are
one bus away, but connected by a transformer instead of a line, would be in scope. This
would seem technically inappropriate, as a transformer would typically have a higher
impedance than 10 miles of line and therefore premature reclosing at these substations
should not affect generators one bus away in these cases. If such substations were to be
included, it would unnecessarily bring into scope many more reclosing relays than intended
by FERC Order No. 758. AEP envisions voting affirmative on this proposed standard if our
concerns regarding scope are eventually addressed.
No
AEP will reserve its comments on the proposed implementation plan until its concerns on
scope are eventually addressed. Due to the current volume of standards development
activity, AEP is not able to apply the same level of rigor to this request for comment as we
would normally. As a result, the comments provided in this response are those we deemed
the most significant, and do not necessary reflect all the issues that AEP may, at some time,
choose to address.
Individual
Michelle D'Antuono
Occidental Chemical Corp. (Ingleside Cogeneration LP)
Yes
Ingleside Cogeneration agrees with the distinctions that the project team has made to
determine which automatic reclosing components may pose a risk to the BES, and therefore
should be subject to PRC-005-3. Clearly those that are incorporated in an SPS have a direct
reliability impact. However, it is reasonable to limit applicable to reclosing systems that reside
at or near significant generation facilities. We also agree that an exclusion should be allowed
wherever the relay owner can demonstrate that the generator protection scheme is
configured to withstand a Fault time frame of twice the normal clearing time without severing
the Facility from the BES. This is a very conservative risk threshold and properly focuses
compliance resources on the most prevalent threats to BES performance. Lastly, the limits of
the control circuitry functionality testing are also appropriate. The prior version of PRC-005-3
included testing through the breaker trip coils – which may also inadvertently lock out other
ancillary functions. Since the only reliability concern is that the reclosing relay will misoperate
in a manner that will result in a premature closing signal, it is appropriate that the functional
test required by NERC focuses only on that point.
No
Ingleside Cogeneration believes that the one year time-frame given to incorporate all the
components of Automatic Reclosers newly identified as applicable to PRC-005-3 due to a
generation change in the BA footprint is insufficient. It is appropriate to require the PSMP to
be updated with the new components by that date, but not to conduct the first full set of
maintenance activities. Our primary concern is that Ingleside, as a Generator Owner, will not
receive timely notification that a substantive change has been made. And although we are
willing to reach out to our Balancing Authority on a regular basis – or to establish a
notification process – this is not a coordination activity that either of us have historically
pursued. Furthermore, the recloser relays maintenance is handled during planned outages. At
the very least, we would need an additional three years to schedule and execute the Table 4
maintenance activities in a quality manner. Since a single miss to PRC-005-3 would result in a
big dollar penalty, we believe that there is some reasonable leeway that should be provided.
Four years beyond the date of the generation change is not excessive – particularly since the
failure of reclosing relays has not been found as the cause of a major BES event, or even a
common issue in less extensive failures.
Group
PacifiCorp
Ryan Millard
Yes
Yes
Individual
Nazra Gladu
Manitoba Hydro
No
Although Manitoba Hydro will continue to maintain our “negative” vote for this standard
based on concerns from the PRC-005-2 version, we do offer the following comments to the
SDT in regards to PRC-005-3: (1) Table 1-4(a), (c), (f) - Manitoba Hydro suggests that the
maintenance activity for electrolyte level inspections would be more appropriately specified
on intervals of six calendar months, rather than on a four month basis. It is our experience
that maximum maintenance intervals of 6 months are adequate at addressing reliability.
Requiring four month intervals would be needlessly burdensome to industry without
achieving additional reliability benefit. Moreover, the maintenance activities which require
inspections to be completed every 18 months will oblige entities to make an additional site
visit every second year. In effect, entities are being asked to check equipment (e.g. electrolyte
levels) on month 16, return on month 18 to check equipment components such as ohmic
values, charge float voltage, etc, and then required to return again on month 20 to check
electrolyte levels, which is excessive. Instead, Manitoba Hydro suggests a more manageable
maximum maintenance interval of 4 calendar months for these types of maintenance
activities (station dc supply voltage, electrolyte level and for unintentional grounds).
No
Although Manitoba Hydro will continue to maintain our “negative” vote for this standard
based on concerns from the PRC-005-2 version, we do offer the following clarifying comments
to the SDT regarding PRC-005-3: (1) General comment - the words “Automatic Reclosing
Components” are both capitalized and de-capitalized throughout the document. For example,
within the definition of a Protection System Maintenance Program (PSMP) the words are decapitalized, but are then capitalized in PRC-005-3 R3. For consistency, Manitoba Hydro
suggests selecting one or the other. (2) Definitions of Terms Used in Standard, PSMP capitalize the word “component” for consistency with the rest of the standard. (3)
Background 4, Retirement of Existing Standards, Implementation Plan for Requirements R1,
R2 and R5, Implementation Plan for Requirements R3 and R4, Implementation Plan for
Requirements R1, R2 and R5 and Implementation Plan for Requirements R3 and R4 - replace
“Board of Trustees” with “Board of Trustees’” for consistency with other standards.
Individual
Travis Metcalfe
Tacoma Power
Yes
Additional Comments- 1. In the definition of a PSMP, captialize ‘components’. 2. In the
definition of a PSMP (including Supplementary Reference), capitalize ‘automatic reclosing’. 3.
In the Implementation Plan, change “The existing standard PRC‐005‐2 shall be retired at
midnight of the day immediately prior to the first day of first calendar quarter…” to “The
existing standard PRC‐005‐2 shall be retired at midnight of the day immediately prior to the
first day of the first calendar quarter…”
Yes
Individual
Alice Ireland
Xcel Energy
Yes
We are supportive of the changes made. But we do have two additional comments: a. The
inclusion of Table 4-2(b) in PRC-005-3 raises the concern of where this testing would have
been required in PRC-005-2 and raises uncertainty about the SDT's intentions for the testing
requirements for all the various possibilities for actuation of SPS mitigating devices. We were
under the impression that row 1 of Table 1-5 in PRC-005-2 required 6 year verification of trip
coils or actuators of circuit breakers or other SPS mitigating devices. What if an SPS calls for
the closure of a normally open breaker and that close signal is accomplished via some means
other than a reclosing relay? Where would the testing of such a breaker closure be required
by PRC-005-2 or PRC-005-3? The way PRC-005-3 Table 4-2(b) is phrased it would appear that
trip coil operations for circuit breakers in protection systems or SPS's would be required per
Table 1-5, row 1 and that close coils that are parts of reclosing schemes are required per
tested by Table 4-2(b), row 1, but there does not appear to be testing requirements for any
other SPS mitigating devices such turbine runbacks, closure of normally open breakers,
disconnect operators, etc. Please clarify testing requirements for SPS mitigating devices
outside of breaker trip coils (Table 1-5, row 1) and close coils as utilized in SPS reclosing
schemes (Table 4-2(b)) - e.g. turbine throttle valve runback, LTC blocking or enabling, closure
of normally open breakers, MOD operation, etc., etc. This appears to be a reliability gap in
both PRC-005-2 and PRC-005-3. b. The applicability of reclosing to the Generator Owner &
Transmission Owner is dependent upon the GO & TO knowing the characteristics of the
Balancing Authority. GOs & TOs do not have this knowledge. There should be an obligation of
the BA to inform (and update as needed) the GO and TO of the gross MW value of the largest
unit in the BA footprint (or determine the appropriate entity to update the GO & TO). This
could be accomplished by adding BA’s as an applicable entity to PRC-005-3 and adding a
requirement for this notification of TO’ s and GO’s by the BA to PRC-005-3. Alternatively, the
applicable entities for PRC-005-3 could be left as is and the requirement for BA’s to notify
TO’s and GO’s could be accomplished by adding a new requirement to a more appropriate
standard.
No
The implementation plan for the initial implementation of the program allows for a gradual
implementation of requirements R3 and R4 for reclosing relay maintenance activities for
those relays determined to be in scope such that 30% must be compliant within 36 months of
regulatory approval, 60% compliant within 60 months of regulatory approval, and 100%
compliant within 84 months of regulatory approval. The additional implementation plan
requires 100% compliance within the next following calendar year even in those
circumstances where the retirement of the largest unit in the balancing authority would result
in an entirely different set of reclosing relays to be in scope. For consistency, it would be far
more reasonable for the additional implementation plan to be aligned with the requirements
of the original implementation plan for R3 and R4. Specifically, entities should be compliant
with R1, R2, and R5 for the newly in scope schemes at the start of the first calendar quarter
12 months following notification of a change in generation necessitating additional reclosing
relays be added to the maintenance program or change in the largest unit in the BA area. For
requirements R3 and R4, entities shall be 30% compliant within 36 months following
notification of a change in generation necessitating additional reclosing relays be added to the
maintenance program or change in the largest unit in the BA area, 60% compliant within 60
months following notification of a change in generation necessitating additional reclosing
relays be added to the maintenance program or change in the largest unit in the BA area and
100% compliant within 84 months following notification of a change in generation
necessitating additional reclosing relays be added to the maintenance program or change in
the largest unit in the BA area.
Individual
Daniel Duff
Liberty Electric Power
No
4.2.6.1 uses the phrase "greater than the gross capacity of the largest BES generating unit
within the Balancing Authority Area" as one determinant for inclusion of relays into the
standard. However, generators do not have a wide area view of the system, and cannot
determine the gross capacity of the largest BES generating unit. Does this value include all
generation which could trip simultaneously at a single generating location? All generation
which is connected through a single step-up transformer? Further, changes outside of the
control of a generator could move relays in or out of the program. If retirement of an asset
lowers the gross capacity value of the largest BES generating unit, would relays immediately
be pulled into the program? Finally, there is no requirement for the BA to provide the gross
capacity value to generation owners. The BA should be added to the list of covered entities,
with a requirement to provide to all entities in their balancing area notice of the gross
capacity of the largest generating unit once per calendar year, and within 30 days of a change
in this value. Another section should be added to the standard to list the implementation
requirements for existing assets when a covered relay enters the program.
No
The program as written requires 30% compliance at 60 months. This implies two instances of
12-year maintenance have to occur in 5 years, or 19 years earlier than should be required.
The plan should be changed to all relays must have the first maintenance completed by 144
months from the effective date of the standard.
Individual
David Jendras
Ameren
Agree
We agree with the SERC Protection & Control Subcommittee (PCS) comments and include
them by reference.
Individual
Bill Fowler
City of Tallahassee
Yes
Yes
Individual
Michael Falvo
Independent Electricity System Operator
No
The IESO believes that the analysis required by the Footnote 1 is out of the scope of PRC-0053, which is to document programs for the maintenance of all Protection Systems and
Automatic Reclosing affecting the BES so that they are kept in working order. In addition, the
analysis required by the Footnote 1 is vague and difficult to assess compliance. In the IESO’s
view, contingencies and related tests performed in transient simulations should be defined in
the planning standards (eg. the TPL standards), instead of PRC-005-3 which is drafted for
maintenance purposes. We suggest removing the Footnote 1 from the draft standard, or in
case it is retained it should be revised to address the aforementioned concerns.
No
We appreciate the SDT’s effort to insert appropriate wording to remove a potential conflict
with Ontario regulatory practice with respect to the effective date of the standard. However,
there are still a couple of places where this insertion is missing. Please insert: “, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.” prior to the wording “,or in those jurisdiction….” in Section 4 on P.2 and in the
first paragraph under the Retirement of Existing Standards” on P.3.
Individual
Gerald Farringer
Consumers Energy
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007-17.2 Protection
System Maintenance and Testing - Phase 2 (Reclosing Relays) PRC-005-3 since the standard
does not address how each entity is expected to obtain the required information “the gross
capacity of the largest BES generating unit with the Balancing Authority Area” (in section
4.2.6.1) and know when it changes.
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007-17.2 Protection
System Maintenance and Testing - Phase 2 (Reclosing Relays) PRC-005-3 since the standard
does not address how each entity is expected to obtain the required information “the gross
capacity of the largest BES generating unit with the Balancing Authority Area” (in section
4.2.6.1) and know when it changes.
Individual
Anthony Jablonski
ReliabilityFirst
Yes
ReliabilityFirst votes in the affirmative because the modifications to this standard further
establishes minimum maintenance activities for Automatic Reclosing Component Types and
the maximum allowable maintenance intervals. ReliabilityFirst offers the following comments
for consideration: 1. Table 4-2(a) and 4-2(b) - ReliabilityFirst seeks the technical justification
for the maximum maintenance interval of 12 years for unmonitored control circuitry
associated with Automatic Reclosing. 2. Applicability section 4.2.6.1 - ReliabilityFirst
recommends adding the term “nameplate rating” to clarify which generating plants are
required have Automatic Reclosing applied. Without this clarifier included, the term “total
installed gross generating plant capacity” is subject to interpretation. For example, a plant
may have multiple different values for its gross generating plant capacity but a plant will
always have one static nameplate rating. The term “nameplate rating” is also consistent with
the new NERC BES definition language.
Individual
Tracy Goble
Consumers Energy Co.
Consumers Energy Co.
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007-17.2 Protection
System Maintenance and Testing - Phase 2 (Reclosing Relays) PRC-005-3 since the standard
does not address how each entity is expected to obtain the required information “the gross
capacity of the largest BES generating unit with the Balancing Authority Area” (in section
4.2.6.1) and know when it changes.
Group
Pepco Holdings Inc & Affiliates
David Thorne
No
1) In section 4.2.6.1 the term “gross generating plant capacity” is used. We assume this refers
to nameplate MVA ratings. To avoid confusion as to what unit of capacity (MVA or MW) is to
be used to evaluate these criteria we suggest the phrase be clarified as “gross generating
plant capacity (in MVA)”. 2) NERC’s System Analysis and Modeling Subcommittee (SAMS)
recommended limiting the applicability of automatic reclosing within this standard to only
those installations that would impact the reliability of the BES. Section 4.2.6.1 uses criteria
based on the “gross generating plant capacity”. Neither the PRC-005-3 standard itself, nor the
Supplementary Reference document explains how to calculate this gross capacity number.
Consider a generating plant that has a total of 600 MVA of installed capacity connected to a
230kV bus. There are also units within the same “power plant” with 200 MVA of capacity
connected to a 69kV bus. The 230kV and 69kV busses are interconnected by an
autotransformer. The “gross generating plant capacity” is 800 MVA, however 200 MVA of this
is connected below 100kV and is not considered BES generation. If it is not considered BES
generation, then it should be excluded from the calculation of gross plant capacity in Section
4.2.6.1, as the loss of this generation would not directly affect the reliability of the BES. 3) In
some switchyard arrangements generating units within the same power plant are connected
to separate switchyard busses that are not connected together. This may be done for
reliability reasons and to control fault current levels. In these situations, the calculation of
gross plant capacity in Section 4.2.6.1 should be based only on the amount of generation
directly connected to the individual bus, and not the total amount in the plant. 4) The NERC
SAMS review concluded that automatic reclosing mal-performance affects BES reliability
when “inadvertent reclosing near a generating station subjects the generation station to
severe fault stresses”. The concern appears to be potential shaft torque damage, or
instability, of rotating machines to automatic reclosing mal-performance. That being the case,
generation sources that are not subject to severe fault stresses, such as inverter based
generation, or static reactive sources (SVC’s, capacitor banks, etc.) should not be included in
the calculation of gross plant capacity. However, since synchronous condensers are subject to
the same fault stresses as synchronous generators they should probably be included in the
gross plant generation calculation, providing they are interconnected at 100kV, or above. 5)
To adequately address the concerns raised in the above sets of comments we suggest Section
4.2.6.1 be re-worded as follows to provide clarity and eliminate confusion on how to evaluate
this plant capacity calculation: “Automatic Reclosing applied on the terminals of Elements
connected to the BES bus located at generating plant substations where the total installed
gross generating plant capacity (in MVA) connected to that bus is greater than the gross
capacity (in MVA) of the largest BES generating unit within the Balancing Authority Area.” In
addition, a qualifying footnote defining “gross generating plant capacity” needs to be added
as follows: “For application of 4.2.6.1 gross generating plant capacity is defined as the sum
total of the nameplate ratings, expressed in MVA, of all BES rotating machine generating units
(including synchronous condensers) that are connected to a common BES switchyard bus.”
Also, specific examples showing how to calculate “gross generating capacity” should be
included in the Supplemental Reference document in order to illustrate and clarity the issues
described in the above comments. How will the applicable functional entities be aware of the
largest (or change in the largest) BES generating unit within the BA area?
No
In order to verify the reclosing scheme performance on any newly identified busses, resulting
from generation capacity increases, it may require scheduling sequential line outages on all
BES lines emanating from the bus in order to test breaker auto-reclosing operations. Also,
based on system operating conditions, these individual line outages may require coordination
with certain generation outages. As such, due to the outage coordination necessary to
perform this testing, it may not be possible to complete all testing and maintenance activities
on these newly identified facilities by the end of the following calendar year. For this reason,
we would suggest the following language (similar to that used in the first bullet of R3/R4
Section 5 of the April 2013 draft of the PRC-005-3 Implementation Plan) be used for the
implementation plan for these newly identified Automatic Reclosing Components: “The
responsible entities must complete the maintenance activities, described in Table 4, for any
newly identified Automatic Reclosing Components, resulting from the addition, or retirement,
of generating units; or increases of gross generation capacity of individual generating units or
plants within the Balancing Authority area, by the first day of the first calendar quarter thirtysix (36) months following implementation of the capacity change, which resulted in the
identification of these new Automatic Reclosing Components (or, for generating plants with
scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage
Individual
John Seelke
Public Service Enterprise Group
No
Automatic reclosing systems, except for those which are an integral part of an SPS, are not
part of Protection Systems that are designed and installed to detect and protect the BES from
damage from faults and to keep blackouts localized, i.e., prevent cascades. Autoreclosing
relays and systems are installed simply to automate an action by a system operator to close a
breaker which automatically tripped, and with one specific possible exception, contribute very
little to BES reliability. Besides the SPS, the one possible exception may be in those areas
where by virtue of the transmission system configuration rapid reclosing of a tripped breaker
is needed to minimize stability issues. PSEG agrees that reclosing relays may be significant to
that specific circumstance, i.e., where rapid action is needed to avoid system instability. To
identify those specific locations and circumstances and limit the inclusion of such relays to
those where it is necessary, PSEG suggests that the drafting team incorporate language
similar to that in the Transmission Relay Loadability Standard PRC-023-2 R6 which could be
modified for PRC-005-3 to read as follows: “Each Planning Coordinator shall conduct an
annual assessment to determine the specific locations/circuits in its Planning Coordinator
area for which Transmission Owners, Generator Owners, and Distribution Providers with
automatic reclosing relays must comply with the maintenance and testing requirements for
such relays under this standard.” The Planning Coordinator has the expertise and skills to
make this determination; many if not most BES asset owners do not. Power systems are
designed to deal with permanent faults, not temporary faults. The extra cost of inclusion of
many automatic reclosing relays in the maintenance and testing program would yield little or
no benefit to reliability of the BES. Only those defined as essential by the Planning
Coordinator should be included in this Standard.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
No
The selection criteria proposed to identify the reclosing relays that affect the reliability of the
Bulk Electric System remains unclear. Please clarify what is meant by “BES elements at
substations one bus away from generating plants”. How is the one bus criterion applied at a
generating station with power transformation and multiple voltages?
No
The implementation plan should be based upon the existing maintenance schedules for the
affected BES components.
Individual
Kayleigh Wilkerson
Lincoln Electric System
Agree
MRO NERC Standards Review Forum (NSRF)
Individual
Jonathan Meyer
Idaho Power Company
Yes
No
The change in generation could bring in significant numbers of additional units to be added to
the testing and maintenance procedures. We would prefer a percentage based approach
similar to the implementation plan for the other table items in PRC-005-2.
Group
Dominion
Louis Slade
No
The SDT did not address concerns relative to how an entity could determine the gross
capacity of the largest BES generating unit within the Balancing Authority Area. Dominion
suggests the SDT include a requirement that the BA post or make such information available
to all entities in its area. The SDT did not address concerns that only planning entities are
typically afforded access to the models or information, or have the technical skills necessary
to be able to make the determination necessary to allow the exclusion included in footnote 1.
No
Given that most of the Maximum Maintenance Intervals appear to be in the 4-6 year range,
we believe that implementation for newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area should be extended to allow up to 36
months from BA notification of such change
Individual
Scott Langston
City of Tallahassee
Yes
Yes
Group
SERC Protection and Controls Subcommittee
David Greene
Yes
1) Please provide FAQ examples to clarify the meaning of ‘total installed gross generating
plant capacity is greater than the gross capacity of the largest BES generating unit’. Our take is
the gross MVA for FAC-008 would be appropriate. But there are several MOD standards,
including some pending FERC approval, that will prove MW and MVAR ‘capability’ not
‘capacity’. 2) We request that the SDT modify the FAQ 2.4.1 to include “typically IEEE Device
No. 79” in referring to the Automatic Reclosing relay because this helps clarify the scope.
Begin the answer with “Yes. Automatic Reclosing includes reclosing relays (typically IEEE
Device No. 79) and the associated dc control circuitry.”
No
1) We prefer that maintenance for newly identified Automatic Reclosing Components be
completed within 3 calendar years. This is more consistent with the phased in approach that
applies to the overall implementation. 2) We prefer a single document with the
implementation plan; please combine the 2 documents. The comments expressed herein
represent a consensus of the views of the above-named members of the SERC EC Protection
and Control Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.
Group
North American Generator Forum Standards Review Team
Patrick Brown
No
This standard presents compliance documentation uncertainties for applicable reclosing
relays defined in Applicability Section 4.2.6.1 “Automatic Reclosing applied on the terminals
of Elements connected to the BES bus located at generating plant substations where the total
installed gross generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area”. This standard now assumes that
GO/TOs are going to coordinate and document that they have contacted the BA to determine
the largest unit in the area and then determine if the reclosing relays are/are not applicable
but does not mention it in the measures. How much coordination and documentation is
required by a GO and its associated SWYDs TO to prove that the generation facility does or
does not exceed the largest BES unit? Does this become part of a PRC-001 requirement to
coordinate protection systems?
No
1. Regarding the implementation plan for this project, the SRT is concerned with the
following: “For Automatic Reclosing Component maintenance activities with maximum
allowable intervals of twelve (12) calendar years, as established in Table 4: The entity shall be
at least 30% compliant on the first day of the first calendar quarter sixty (60) months
following applicable regulatory approval of PRC-005-3.” This would require two cycles of 12-
year maintenance in five years for 30% of your affected equipment. We recommend that the
implementation plan be changed to require that 100% of the affected relays have one
maintenance performed by 144 months from the implementation date of the standard. 2. The
implementation plan states: “For activities being added to an entity’s program as part of PRC005-3 implementation, evidence may be available to show only a single performance of the
activity until two maintenance intervals have transpired following initial implementation of
PRC-005-3.” However, If there is no specific ‘bookend’ required, and the cycle is truly a 12year cycle, no evidence of testing or maintenance should be required prior to 144 months
from the enforcement date of the standard; but the proposed implementation plan requires
the work at 36 months, 60 months, and 84 months, which is obviously short of a 12-year
cycle. A Compliance Enforcement Authority could apply this in the following manner: Entity Y
has four reclosing relays, all tested and installed on August 1, 2004. The ne PRC-005 Standard
becomes effective on July 1, 2014. On August 2, 2014 entity Y could be found in violation if
one of the four relays has not gone through the new 12-year required cycle. If the language
was changed to 100% compliance by 144 months, with all the earlier steps eliminated, it
would work. Specific language needs to be in place noting that no evidence shall be required
for any testing prior to the enforcement date, and the 12-year clock starts on that day. The
following change would need to be made also: “For activities being added to an entity’s
program as part of PRC-005-3 implementation, evidence may be available to show only a
single performance of the activity until 288 months following the enforcement date of PRC005-3.”
Individual
Louis C. Guidry
Cleco
No
We do not believe reclosing relays are protective devices and therefore are not subject to this
level of oversight. Second, the strongest justification was that if the relay failed to operate
correctly and reclosed instantaneously, the generator would be subject to additional fault
duty. We have not seen such a failure and do not see the justification for including reclosing
relays or restoration devices in a Protection System Maintenance & Testing Standard. Major
storm events near the station or breakers failing to latch are far more likely to cause
sequential faults.
No
We do not believe reclosing relays are protective devices and therefore are not subject to this
level of oversight. Second, the strongest justification was that if the relay failed to operate
correctly and reclosed instantaneously, the generator would be subject to additional fault
duty. We have not seen such a failure and do not see the justification for including reclosing
relays or restoration devices in a Protection System Maintenance & Testing Standard. Major
storm events near the station or breakers failing to latch are far more likely to cause
sequential faults.
Group
Oklahoma Gas & Electric
Terri Pyle
No
In the draft Standard and the Supplementary Reference, a lot of detail was deleted from the
definition of Automatic Reclosing. The revised definition no longer includes the phrase "but
excluding breaker internal controls such as anti‐pump and various interlock circuits." Does
this imply that those components are now included in the definition of Automatic Reclosing?
In reference to these components, the Supplementary Reference document (in section
15.8.1) states that, "These components are not specifically addressed within Table 4, and
need not be individually tested. They are indirectly verified by performing the Automatic
Reclosing control circuitry verification as established in Table 4." The Standard needs to be
explicit on what is and is not required to be tested as part of an entities PRC-005 maintenance
and testing program rather than leaving it open to interpretation. In 4.2.6.1 of the
Applicability section of the draft Standard, reference is made to the total installed gross
generating capacity of a generating plant which is then compared to the gross generating
capacity of the largest BES unit in the Balancing Authority Area. It would be helpful if the SDT
provided some examples (including some that references how to address combined cycle
units/plants) in the Suppementary Reference document to help entities understand and
properly apply Section 4.2.6.1 of the Standard.
Yes
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
No
) There are currently two NERC approved projects filed at FERC (PRC-005-1.1b and PRC-0052). NERC should consider waiting to proceed with this project until the current projects are
ruled on and FERC provides further direction. 2) For 4.2.6, for reclosing capability, it is unclear
what functionality is to be tested. Please define. 3) For PRC-005-3 section 4.2.6.2, please
provide the technical basis for this application of the Standard. Specifically, this application
states for Automatic Reclosing: “Applied on BES Elements at substations one bus away from
generating plants specified in section 4.2.6.1 when the substation is less than 10 circuit miles
from the generating plant substation.” Please provide the technical basis/reasoning for the
10-mile criteria. At a recent North American Transmission Forum Workshop on Protection
System Maintenance Program it was implied that the 10 mile rule is for cases where a
generator has a short connection to another company’s substation. Please clarify if this is the
case. 4) For PRC-005-3 section R1, consider adding the following language that is used for
PRC-005-1.1b “each Generator Owner that owns a generation or generator interconnection
Facility Protection System...” This is NERC-approved language that has been through the
standards development process and has technical justification through Project 2010-07. 5)
Please provide the technical basis for R1.1 which requires battery testing for DC Supply
Component Type Protection Systems to be time based. 6) Table 1-2 of PRC-005-3 requires
functional testing of non-monitored communication systems on a 4 month cycle. Please
specify NERC’s criteria for the functional testing (what attributes to be tested). Additionally,
specifically define monitoring criteria and data intervals for continuous monitoring of
communications systems (to see if check back (fail/no fail) monitoring is adequate). 7) This
standard presents compliance documentation uncertainties for applicable reclosing relays
defined in Applicability Section 4.2.6.1 “Automatic Reclosing applied on the terminals of
Elements connected to the BES bus located at generating plant substations where the total
installed gross generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area”. This standard now assumes that
GO/TOs are going to coordinate and document that they have contacted the BA to determine
the largest unit in the area and then determine if the reclosing relays are/are not applicable
but does not mention it in the measures. How much coordination and documentation is
required by a GO and its associated switchyards. Does the TO need to prove that the
generation facility does or does not exceed the largest BES unit? Does this become part of a
PRC-001 requirement to coordinate protection systems?
No
1. Regarding the implementation plan for this project, the PPL NERC Registered Affiliates are
concerned with the following: “For Automatic Reclosing Component maintenance activities
with maximum allowable intervals of twelve (12) calendar years, as established in Table 4: The
entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3.” This would require two cycles
of 12-year maintenance in five years for 30% of your affected equipment. We recommend
that the implementation plan be changed to require that 100% of the affected relays have
one maintenance performed by 144 months from the implementation date of the standard. 2.
The implementation plan states: “For activities being added to an entity’s program as part of
PRC-005-3 implementation, evidence may be available to show only a single performance of
the activity until two maintenance intervals have transpired following initial implementation
of PRC-005-3.” However, If there is no specific ‘bookend’ required, and the cycle is truly a 12year cycle, no evidence of testing or maintenance could be required prior to 144 months from
the enforcement date of the standard; but the proposed implementation plan requires the
work at 36 months, 60 months, and 84 months, which is short of a 12-year cycle.
Group
Southern Company
Wayne Johnson
No
1) We believe that there should be a Requirement for the BA to initially inform the TOs and
GOs in their area which units are in scope. Minimally, there must be a requirement that the
BA identify the ‘largest BES generating unit’ and inform all the TOs and GOs in their area.
2)Secondly, related to 1) above, there must be a requirement that the BA inform all the TOs
and GOs in their area when a change occurs related to the ‘largest BES generating unit’.
No
Southern Company believes that the two implementation plans associated with the Standard
are in conflict. It can be interpreted that all automatic reclosing components will be ‘newly
identified’. As such they would be required to be completed by the end of the following
calendar year. We believe that the intent was to have the initial applicable Automatic
Reclosing Components to have the same phased in completion dates that were brought
forward form PRC-005-2. If that was the intent, an potential conflict exists since after the
initial phased in schedule up to 12 yrs is set, a change in the unit applicability could occur one
year later which could in the case of ‘largest unit’ retirement bring many more locations into
scope all of which would be newly indentified and be subject to the one calendar year
requirement. Bottom Line is that the Implementation plan needs to be revisited. Related to
the comment to #2 above, we do not specifically see a timeline identified to include the
following: 1) Identification to identify the units and components covered. 2) Identification of
the components that may be excluded per the Note. 3) Modification to the PSMP 4) Actual
Implementation If the intent is for all this to be covered in R1 and R2, we question this for the
following reasons: • Is this enough time for the initial steps noted above, and • This result in
multiple dates for compliance with R1 and R2
Individual
Brett Holland
Kansas City Power & Light
Agree
SPP - Robert Rhodes
Group
Hydro One Networks Inc.
Sasa Maljukan
Agree
IESO and NPCC RSC
Individual
Brian Evans-Mongeon
Utility Services
Agree
NPCC Reliability Standrds Committee
Group
ACES Standards Collaborators
Jason Marshall
No
(1) We find that the changes are non-substantive and do not present a problem. However, we
continue to be concerned about modifying this standard when there is another version
pending before the Commission. We believe it will only cause confusion. Given that this
standard is historically one of the top ten most violated standards and the most violated nonCIP standard, industry does not need to be burdened with further confusion that will only
cause additional violations. One example of the confusion is the implementation plan of the
proposed draft. If the PRC-005-2 standard was already enforceable, the implementation plan
could focus only on auto-reclosing which would avoid the confusion. (2) Because there were
no general feedback questions asked and there is no other appropriate question to place our
other concerns with the proposed standard, we are inserting them here. (3) The
implementation plan creates confusion with dual conflicting parallel dates. The confusion is
understood by comparing PRC-005-2 implementation plan to the PRC-005-3 implementation
plan. For example, the implementation plan for PRC-005-2 requires the responsible entity to
be at least 30 percent compliant on the first day of the first calendar quarter 24 months
following applicable regulatory approval for maintenance activities with a three year interval.
The PRC-005-3 implementation plan is identical. Thus, if FERC approves PRC-005-2 such that is
has an effective date of June 1, 2014, the responsible entity will have to be 30 percent
compliant with R3 and R4 for equipment with three-year interval maintenance cycles by July
1, 2016. If FERC then approves PRC-005-3 such it has an enforceable date of September 1,
2015, the responsible entity will have to be 30 percent compliant with R3 and R4 for
equipment with a three-year interval maintenance cycles by October 1, 2017. Thus, there will
be two different conflicting dates for the 30 percent compliance level. Which applies? If the
second applies, this is like resetting the compliance date. Furthermore, there is unnecessary
confusion with the 30 percent compliant metric, as this could change from the two different
implementation plans if additional equipment is installed during the implementation plan.
There are too many compliance risks of having implementation plans overlapping or coming
into effect in a short amount of time. This proposal mirrors the issues of the implementation
plans with CIP version 4 and CIP version 5. FERC granted an extension in order to allow
responsible entities to more efficiently utilize resources to transition to the next version. We,
as an industry, should learn from this experience and not rush to the next version of the
standard prematurely. (4) We disagree with the statement (second paragraph first sentence
and first bullet) in the general considerations section of the implementation plan that states
the responsible entities must be prepared to identify Automatic Reclosing components during
the transition from version 2 to version 3. While we agree that this ultimately will be
necessary at some point in the transition to prepare for the compliance date, we are
concerned that an auditor could interpret this implementation plan as requiring the
responsible entity to develop an inventory of Automatic Reclosing components prior to the
effective compliance date. A standard cannot retroactively require actions to be completed
prior to its effective date. This identification of Automatic Reclosing components presents
serious compliance issues and we recommend striking it in its entirety. (5) We disagree with
the statement (second paragraph first sentence and second bullet) in the general
considerations section of the implementation plan that states the responsible entities must
be prepared to identify “whether each component has last been maintained according to
PRC-005-2 (or the combined successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC011-0, PRC-017-0, or a combination thereof”. We do not have an issue if this statement
applies only to the Protection System components because they have been under these
standards for some time. However, this statement could be viewed as applying to Automatic
Reclosing components and it should not because they have never been subject to any
standard. While most responsible entities will have maintained their Automatic Reclosing
components, they simply were not required to maintain them and, thus, the documentation
may not be sufficient to demonstrate prior maintenance activities. Maintenance activities for
Automatic Reclosing components are not required until PRC-005-3 is enforceable. (6) We do
not understand why PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 will not be retired for
156 months or 13 years. That is quite a long time for these standards to be effective in
parallel. This poses a potential for double jeopardy and we recommend retiring these
standards at the same time the new standard becomes enforceable. (7) We find the language
in section 3 of the implementation plan for R3 and R4 confusing. That section proposes to
require the responsible entity to comply with R3 and R4 for 30 percent of the Protection
System components that are subject to three-year maintenance intervals. However, this
language “or, for generating plants with scheduled outage intervals exceeding two years, at
the conclusion of the first succeeding maintenance outage” is added as a caveat. We are
unsure how to interpret it. Does this mean that if a generator has three-year maintenance
interval that 30 percent of its Protection System components must meet compliance at the
conclusion of the first succeeding maintenance outage or it is an exception and all of its
Protection System components must meet R3 and R4 compliance obligations by the same
date? (8) Section 4.2.6.1 of the applicability section of the standard is inconsistent with the
proposed definition of the Bulk Electric System (BES) and may be inconsistent with existing
definitions that vary by region. Since Inclusion I2 includes the generator and generator step
up (GSU) transformer as part of the BES, what exactly would constitute the BES bus? The low
side bus of the GSU transformer, the high side bus or some other location? All of these are
part of the BES. This section needs further clarification. (9) Section 4.2.6.2 of the applicability
section of the standard needs further refinement. What would constitute one bus away from
the generating plant? What constitutes the plant? The electrical machine, turbine, GSU, and
switchyard? What if there is more than one switchyard? What if the switchyard is not on the
immediate property but short distance away? Some additional refinement would help to
answer these questions. We suggest utilizing the GSU as demarcation point to help clarify.
(10) The evidence retention section needs to clarify that the responsible entity is not required
to keep “documentation of the two most recent performances of each distinct maintenance
activity “during the initial implementation of the standard for Automatic Reclosing
components. This clarification will help avoid the problems that occurred with PRC-005-1
when auditors requested evidence from before the effective date of the requirements. The
bottom line is that a standard cannot be retroactive and cannot compel evidence from before
the effective date. This needs to be clear. (11) The evidence retention period is excessively
long, is inconsistent with the Reliability Assurance Initiative (RAI), and is inconsistent with the
Rules of Procedure. Since some Automatic Reclosing component maintenance intervals are 12
years, retaining the two most recent performances of each maintenance activity could result
in evidence retention periods of almost 36 years. Entire careers will be worked before this
evidence can be destroyed. Given the length of time, it is highly likely that responsible entities
will lose some of the documentation which will result in paper violations that do nothing to
support reliability. This is contrary to the RAI which is trying move to a forward looking
compliance model that provides reasonable assurance of compliance. Furthermore, the
evidence retention period is longer than the six year audit cycle for TOs, GOs, and DPs which
is inconsistent with section 3.1.4.2 of Appendix C - Compliance Monitoring and Enforcement
Program of the NERC Rules of Procedures. This section is very clear that the evidence
retention cannot exceed a period prior to the last audit. (12) We suggest that Table 4-2(a)
should be clarified that it only applies to those Automatic Reclosing components that are at
large generator plants or close to large generator plants per applicability section 4.2.6.1 and
4.2.6.2 respectively. Otherwise, there may be confusion when compliance and enforcement
personnel look at the table. They may view that it will apply to all Automatic Reclosing
components that are not an integral part of a Special Protection System (SPS) including those
are not close to large generators.
No
(1) We agree with the need for the additional implementation plan but find it confusing. First,
we think that the compliance date should be identified as some interval after the commercial
in-service date of the change in generation or the official retirement date. Otherwise, there
could be confusion in which year the newly applicable Automatic Reclosing components must
be compliant. Consider a new unit begins testing on December 1, 2013 and goes commercial
January 31, 2014. One could interpret the language in the implementation plan to require the
maintenance activities to be completed by December 31, 2014 or December 31, 2015. (2) To
avoid the confusion that occurred with PRC-005-1, the implementation plan should state very
clearly that the initial maintenance activities must be performed by the compliance date and
that no evidence of prior maintenance activities is required. In essence, the compliance date
established in this implementation plan due to changes in generation and the overall
implementation plan should be very clear that the compliance date established in these plans
is the start of the initial interval. To allow the interval to start before the compliance date
would be equivalent to making the standard retroactive.
Group
SPP Standards Review Group
Robert Rhodes
No
In the definition of Automatic Reclosing a goodly amount of detail has been deleted from the
definition. Does the excluded portion of the definition, specifically breaker internal controls
such as anti-pump and various interlock circuits still fall under the standard? The reference
document implies that they do, but the revised wording is not clear to us. In 4.2.6.1 reference
is made to the total installed gross generating capacity of a generating plant which is then
compared to the gross generating capacity of the largest BES unit in the Balancing Authority
Area. Shouldn’t the reference to the largest unit also state the installed gross capacity of the
unit to prevent any confusion? Also, in selecting to use gross generation numbers, we wonder
if consideration was given to generation values used in other standards such as BAL-002 and
BAL-003 which tend to lean toward net generation values rather than gross. In the
Supplementary Reference we suggest replacing the term ‘supervisor’ on Page 92 in Section
15.8.1 FAQ in the 7th line of the 1st paragraph in the response to the 2nd question with
‘supervision’. The sentence would then read ‘…applicability of associated
supervision/conditional logic and the…’.
Yes
Individual
Texas Reliability Entity, Inc.
Texas Reliability Entity, Inc.
No
We feel that the proposed maintenance activities in tables 4-1 and 4-2 do not necessarily
address all of the typical failure modes of reclosing relays and control circuitry associated with
them and offer the following comments: 1) Definition of Automatic Reclosing: Is it the SDT’s
intention that “Control circuitry associated with the reclosing relay” includes a separate sync
check relay that may be used in the reclosing scheme? The definition is not clear and the SDT
may want to clarify. 2) Table 1-3: The SDT may want to consider adding an activity to verify
voltage signals are provided for reclosing relay sync check functions. 3) Table 4-2(a) and 42(b): The SDT may want to consider including activities to verify that auxiliary relays in the
reclosing scheme (i.e. bus differential or breaker failure lockout relays) properly inhibit
reclosing. The SDT may also want to consider including activities to verify sync check functions
depending on the system design (i.e. hot bus-hot line, hot bus-dead line, etc.). These two
activities are necessary to verify that the reclosing scheme will not issue a reclose signal when
it is not desired. 4) Table 4-2(b): Suggest rewording the 2nd block to say “Verify all paths of
the control circuits ***including all auxiliary relays*** associated with Automatic Reclosing…”
Yes
Individual
Bradley Collard
Oncor Electric Delivery Company LLC
Yes
Yes
Individual
Ryan Walter
Tri-State Generation and Transmission Association, Inc.
No
Tri-State Generation and Transmission Association, Inc. finds that Table 4-1 is too inclusive
and should include a restriction for only automatic reclose relays/functions that are required
for system stability, with a list of which those should be as per SAMS, such as SPS and near
generation. Table 4-1, as written, captures more equipment than is necessary, creating an
undue administrative burden with little, to no, benefit to the reliability of the BES. Adding a
compliance liability for reclosing relays that do not impact system stability could lead to
industry removing many of the reclosing relays used for expeditious restoration. This does not
improve system reliability. Also, since the majority of reclosing functions utilizing
microprocessor relays reside within the microprocessor protective relay, the documentation
for this testing will be included within documentation already required and provided under
Table 1-1. To provide a separate list and documentation for all BES microprocessor reclosing
functions will create an undue administrative burden on industry with little to no value to the
BES. Further, we recommend the applicability of reclosers is changed to “reclosers identified
by the entity’s selection criteria to be critical to the operation of the BES per its Maintenance
and Testing Program” to better align with FERC order 758 where FERC recommends “selection
criteria should be used to identify reclosing relays that affect the reliability of the Bulk-Power
System”. Tri-State suggests that Table 4-2(a), Control Circuitry Associated with Reclosing
Relays that are NOT an Integral Part of an SPS, be removed in its entirety or a maintenance
activity specific to the circuitry be defined. The maintenance activity required in Table 4-2(a) is
not a maintenance activity that verifies the control CIRCUITRY. A close “command” is external
to the hardware circuitry. Whether or not that command occurs, does not confirm the
functionality of the close circuitry hardware. The timing test for a reclosing function is also
usually included within the testing of the protective relay, which is part of Table 1-1 and Table
4-1, making this table slightly redundant to what already exists. A definition of “premature”,
giving specific tolerances, will also be required, if kept within the text, to understand at what
point a test would fail or a result would be viewed as “non-compliant”. Any test for a
microprocessor instantaneous reclose would fail this requirement, as the close command is
already present at the beginning of the sequence, hence being “premature”. A PASS test
result showing the reclose command was initiated within the tolerance of the relay but prior
to the setting could be viewed as “premature” and be interpreted as “non-compliant”. A FAIL
test result showing the relay closed well out of the manufacturer tolerance but after the
setting would be viewed as “compliant”. If the text and Table remain, the statement: “Verify
that Automatic Reclosing, upon initiation, does not issue a premature closing command to the
close circuitry” should be changed to, “Verify that the close circuitry operates per engineering
settings, and not sooner than (tolerance) of the setting.”
No
"Prior to the end of the following calendar year" is a very ambiguous implementation plan
and could require entities to be compliant anywhere between 12 and 24 months. TSGT
recommends that the implementation period state 18 months from the first day of the
quarter following component identification.
Group
Colorado Springs Utilities
Kaleb Brimhall
No
1.Concerning facilities, would a reliability based method of determining covered facilities
more likely better serve the reliability of the BES versus the generation based cap method
under 4.2.6? 2.With no standard requiring re-closing relaying be in place, there will be a
tendency to disable all re-closing relays to avoid facilities coming under this standard.
Abstained from commenting on this question.
Individual
Michael P. Moltane
ITC
No
4.2.6 references a footnote 1 that is an exclusion. How can an exclusion be put into a
footnote? It should be up in the standard, not in a footnote. Regarding 4.2.6.1 for generating
plant substations that have generator outputs at separate kV levels where the switchyards are
not normally tied together are they treated as separate generating plants? Same question for
locations that have generator outputs where the switchyards are not directly tied together.
For a location that has a couple Balancing Authority Areas over it is the largest BES generating
unit determined by the largest Balancing Authority Area?
Yes
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC PCS
Group
Western Area Power Administration
Lloyd A. Linke
No
Further clarification and definition is required regarding the application of the standard to
“premature” closing. Specifically, what is the definition of “premature” and why does the
standard not refer to inadvertent or incorrect auto reclosing. Facilities Section 4.2.6.2 applies
to automatic reclosing applied on the terminals of all BES Elements at substations one bus
away from generating plants specified in Section 4.2.6.1 when the substation is less than 10
circuit miles from the generating plant substation. This Section should be clarified and should
not include BES elements at those substations connected at a different voltage than the
incoming generation circuit. The impedance of any transformation should represent sufficient
isolation. It should be clarified that dc control circuitry and power circuit breaker close coils
are only included with automatic reclosing that is an integral part of a SPS.
Yes
Consideration of Comments
Project 2007-17.2 Protection System Maintenance and
Testing – Phase 2 (Reclosing Relays) PRC-005-3
The Project 2007‐17.2 drafting team thanks all commenters who submitted comments on draft 2 of
PRC‐005‐3 standard for Protection System Maintenance and Testing (Reclosing Relays). The standard
was posted for a 45‐day formal comment period from July 10, 2013 through August 23, 2013.
Stakeholders were asked to provide feedback on the standard and associated documents through a
special electronic comment form. There were 41 responses, including comments from approximately
149 different people from approximately 85 companies representing 7 of the 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404‐446‐2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration of all Comments Received:
PRC-005-3
There were no changes made to the standard.
Implementation Plan:
In response to comments, the drafting team incorporated the “Implementation Plan for Newly
identified Automatic Reclosing Components due to generation changes in the Balancing Authority
Area” into the full Implementation Plan to consolidate the implementation documents.
Numerous commenters disagreed with the implementation period specified in the “Implementation
Plan for Newly identified Automatic Reclosing Components due to generation changes in the Balancing
Authority Area” stating that it was too short to accommodate the potential number of newly identified
Automatic Reclosing Components that could become applicable nor did it provide enough time for
potential outage coordination(s) necessary to perform the required maintenance. Upon
reconsideration, the drafting team agreed that the proposed implementation schedule for newly
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
identified Automatic Reclosing Components was inappropriate and could potentially jeopardize
reliability by forcing entities to take unscheduled outages to become compliant. The drafting team
deemed three years to be sufficient to avoid the reliability concerns and permit entities to implement
maintenance in a manner that would be sustainable in the long‐term.
In response to a comment, the drafting team inserted the jurisdictional pro‐forma language where it
had been inadvertently left out of the Implementation Plan. Additionally, NERC will file the errata
change with the applicable regulatory authorities as necessary for the PRC‐005‐2 Implementation Plan.
To avoid confusion, the drafting team modified paragraph 4 of the Background section to remove the
references to the implementation timing. The timing is already comprehensively addressed in the
implementation plan for each requirement.
Supplementary Reference and FAQ Document:
Additional content was provided to improve the reference document.
Unresolved Minority Views:
A few commenters objected to the development of PRC‐005‐3 prior to regulatory approval of PRC‐
005‐2. The drafting team advised that they are acting in accordance with the schedule NERC
provided to FERC which outlines the timeframes in which NERC will respond to the directives of
FERC Order 758 through the standards drafting process. Specifically regarding reclose relays
(Footnote 37), FERC directed NERC to: “By July 30, 2012, NERC should submit to the Commission
either the completed project which addresses the remaining issues consistent with this order, or an
informational filing that provides a schedule for how NERC will address such issues in the Project
2007‐17 reinitiated efforts.”
Several commenters requested an additional requirement be included in PRC‐005‐3 mandating that
Balancing Authorities provide Transmission Owners, Generator Owners, and Distribution Providers
the information identifying the current largest single generating unit in the Balancing Authority
Area (described in Applicability 4.2.6), and notify those entities (within a specified time) when this
information changes. The SAR for this project does not permit the addition of functional entities to
the Applicability section of this standard; therefore, the drafting team is unable to make the
requested change. The drafting team understands the request but contends that such a
requirement would be more appropriately included in a Reliability Standard applicable to Balancing
Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Consideration of Comments: Project 2007‐17.2 | August 2013
2
Index to Questions, Comments, and Responses
1.
In response to comments, the drafting team revised the previously‐posted draft of PRC‐005‐3
and the Supplementary Reference and FAQ document. Do you agree with these changes? If not,
please provide specific suggestions for improvement. .................................................................. 12
2.
In response to comments, the drafting team developed an “Implementation Plan for Newly
identified Automatic Reclosing Components due to generation changes in the Balancing
Authority Area” Do you agree with this additional Implementation Plan? If not, please provide
specific suggestions for improvement. ........................................................................................... 42
Consideration of Comments: Project 2007‐17.2 | August 2013
3
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load‐serving Entities
4 — Transmission‐dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Guy Zito
Additional Member
Northeast Power Coordinating Council
Additional Organization
2
3
4
5
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2. Greg Campoli
New York Independent System Operator
NPCC 2
3. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4. Chris de Graffenried Consolidated Edison Co, of New York, Inc. NPCC 1
5. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6. Mark Kenny
Northeast Utilities
NPCC 1
7. Kathleen Goodman
ISO - New England
NPCC 2
8. Michael Jones
National Grid
NPCC 1
9. David Kiguel
Hydro One Networks Inc.
NPCC 1
10. Christina Koncz
PSEG Power LLC
NPCC 5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Helen Lainis
Independent Electricity System Operator
NPCC 2
12. Michael Lombardi
Northeast Power Coordinating Council
NPCC 10
13. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
14. Bruce Metruck
New York Power Authority
NPCC 6
15. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
16. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
19. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
20. Brian Robinson
Utility Services
NPCC 8
21. Brian Shanahan
National Grid
NPCC 1
22. Wayne Sipperly
New York Power Authority
NPCC 5
23. Donald Weaver
New Brunswick System Operator
NPCC 2
24. Ben Wu
Orange and Rockland Utilities
NPCC 1
25. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Colby Bellville
2
3
4
5
6
7
8
9
10
Group
Duke Energy
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
3.
Group
Russel Mountjoy
Additional Member
MRO NERC Standards Review Forum (NSRF)
Additional Organization
Region Segment Selection
1. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
2. Chuck Lawrence
American Transmission Company
MRO
1
3. Dan Inman
Minnkota Power Cooperative
MRO
1, 3, 5, 6
4. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
5. Kayleigh Wilkerson Lincoln Electric System
MRO
1, 5, 6
6. Jodi Jensen
Western Area Power Administration
MRO
1, 6
7. Joseph DePoorter
Madison Gas and Electric
MRO
3, 4, 5, 6
8. Ken Goldsmith
Alliant Energy
MRO
4
Consideration of Comments: Project 2007‐17.2 | August 2013
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9. Mahmood Safi
Omaha Public Power District
MRO
10. Marie Knox
Midcontinent Independent System Operator MRO
2
11. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
12. Scott Bos
Muscatine Power and Water
MRO
1, 3, 5, 6
13. Scott Nickels
Rochester Public Power District
MRO
4
14. Terry Harbour
MidAmerican Energy
MRO
1, 3, 5, 6
15. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
16. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
4.
David Thorne
2
3
4
5
6
7
8
9
10
1, 3, 5, 6
Group
Pepco Holdings Inc & Affiliates
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Carlton Bradshaw
Delmarva Power & Light Co RFC
1, 3
2. Carl Kinsley
Delmarva Power & Light Co RFC
1, 3
5.
Group
Louis Slade
Dominion
Additional Member Additional Organization Region Segment Selection
1. Jeff Bailey
Nuclear
2. Chip Humphrey
Power Generation
NPCC 5
5
3. Michael Crowley
Electric Transmission
SERC
1, 3
4. Sean Iseminger
Power Generation
RFC
5
5. Connie Lowe
NERC Compliance Policy SERC
6. Mike Garton
NERC Compliance Policy NPCC 1, 3, 5, 6
7. Randi Heise
NERC Compliance Policy RFC
1, 3, 5, 6
8. Rick Purdy
Electric Transmission
1, 3
SERC
1, 3, 5, 6
6.
Group
David Greene
Additional Member
Additional Organization
1. Paul Nauert
Ameren
2. Bridget Coffman
Santee Cooper
3. George Pitts
TVA
4. Steve Edwards
Dominion VP
5. Phil Winston
Southern Company Services
6. David Greene
SERC
SERC Protection and Controls
Subcommittee
Region Segment Selection
Consideration of Comments: Project 2007‐17.2 | August 2013
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Group
North American Generator Forum
Standards Review Team
Patrick Brown
Additional Member
Additional Organization
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
X
Region Segment Selection
1. Allen Schriver
NextEra Energy Resources
5
2. Steve Berger
PPL Susquehanna, LLC
5
3. Terry Crawley
Southern Company Generation
5
4. Pamela Dautel
IPR-GDF Suez Generation NA
5
5. Dan Duff
Liberty Electric Power
5
6. Mikhail Falkovich
PSEG
5
7. Gary Kruempel
MidAmerican Energy Company
5
8. Katie Legates
American Electric Power
5
9. Don Lock
PPL Generation, LLC
5
10. Joe O'Brien
NIPSCO
5
11. Chris Schaeffer
Duke Energy
5
12. Dana Showalter
E.ON Climate and Renewables
5
13. William Shultz
Southern Company
5
14. Mark Young
Tenaska, Inc.
5
8.
Terri Pyle
Group
Oklahoma Gas & Electric
Additional Member Additional Organization Region Segment Selection
1. Terri Pyle
OG&E
SPP
1
2. Don Hargrove
OG&E
SPP
3
3. Leo Staples
OG&E
SPP
5
4. Jerry Nottnagel
OG&E
SPP
6
9.
Group
Brent Ingebrigtson
Additional Member
Additional Organization
PPL NERC Registered Affiliates
Region Segment Selection
1. Brenda Truhe
PPL Electric Utilities Corporation RFC
1
2. Annette Bannon
PPL Susquehanna, LLC
RFC
5
3.
PPL Montana, LLC
WECC 5
4.
PPL Generation, LLC
RFC
5. Elizabeth Davis
PPL EnergPlus, LLC
NPCC 6
6.
SERC
5
6
Consideration of Comments: Project 2007‐17.2 | August 2013
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
SPP
6
8.
MRO
6
9.
WECC 6
10.
RFC
2
3
4
5
6
7
8
9
10
6
10.
Group
Sasa Maljukan
Hydro One Networks Inc.
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
Hydro One Networks Inc. NPCC 1, 3
2. Paul Difilippo
Hydro One Networks Inc. NPCC 1, 3
11.
Group
Jason Marshall
Additional Member
ACES Standards Collaborators
Additional Organization
Region Segment Selection
1. John Shaver
Arizona Electric Power Cooperative
WECC 4, 5
2. John Shaver
Southwest Transmission Cooperative
WECC 1
3. Shari Heino
Brazos Electric Power Cooperative
ERCOT 1, 5
4. Amber Anderson
East Kentucky Power Cooperative
SERC
5. Scott Brame
North Carolina Electric Membership Corporation SERC
1, 3, 4, 5
6. Mark Ringhausen
Old Dominion Electric Cooperative
RFC
3, 4
7. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
1, 3, 5
12.
Group
Robert Rhodes
Additional Member
Additional Organization
SPP Standards Review Group
Region Segment Selection
1. Timothy Bobb
Westar Energy
SPP
1, 3, 5, 6
2. John Boshears
City Utilities of Springfield
SPP
1, 4
3. Tony Eddleman
Nebraska Public Power District
MRO
1, 3, 5
4. Louis Guidry
Cleco Power, LLC
SPP
1, 3, 5
5. Jonathan Hayes
Southwest Power Pool
SPP
2
6. Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
7. Bo Jones
Westar Energy
SPP
1, 3, 5, 6
8. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
9. Wes Mizell
Westar Energy
SPP
1, 3, 5, 6
10. James Nail
City of Independence, MO
SPP
3
11. Valerie Pinamonti
American Electric Power
SPP
1, 3, 5
12. Ashley Stringer
Oklahoma Municipal Power Authority SPP
4
Consideration of Comments: Project 2007‐17.2 | August 2013
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13.
Group
Lloyd A. Linke
Additional Member
Western Area Power Administration
Additional Organization
2
3
4
5
6
7
8
9
10
X
X
Region Segment Selection
1. Upper Great Plains Region Western Area Power Administration MRO
1, 6
2. Rocky Mountain Region
Western Area Power Administration WECC 1, 6
3. Sierra Nevada Region
Western Area Power Administration WECC 1, 6
4. Desert South West Region Western Area Power Administration WECC 1, 6
5. Colorado Storage Project
Western Area Power Administration WECC 6
14.
Individual
Ryan Millard
PacifiCorp
X
X
X
X
15.
Individual
Wayne Johnson
Southern Company
X
X
X
X
16.
Individual
Kaleb Brimhall
Colorado Springs Utilities
X
X
X
X
17.
Individual
Thomas Foltz
X
X
X
X
X
Individual
Michelle D'Antuono
American Electric Power
Occidental Chemical Corp. (Ingleside
Cogeneration LP)
19.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
X
20.
Individual
Travis Metcalfe
Tacoma Power
X
X
X
X
X
21.
Individual
Alice Ireland
Xcel Energy
X
X
X
X
22.
Individual
Daniel Duff
Liberty Electric Power
X
23.
Individual
David Jendras
Ameren
X
X
X
X
24.
Individual
Bill Fowler
City of Tallahassee
X
25.
Individual
Michael Falvo
Independent Electricity System Operator
X
26.
Individual
Gerald Farringer
Consumers Energy
X
27.
Individual
Anthony Jablonski
ReliabilityFirst
X
28.
Individual
Tracy Goble
Consumers Energy Co.
X
29.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
30.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
31.
Individual
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
X
32.
Individual
Jonathan Meyer
Idaho Power Company
X
18.
Consideration of Comments: Project 2007‐17.2 | August 2013
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
33.
Individual
Scott Langston
City of Tallahassee
X
34.
Individual
Louis C. Guidry
Cleco
X
X
X
X
35.
Individual
Brett Holland
Kansas City Power & Light
X
X
X
X
36.
Individual
Utility Services
X
X
Individual
Brian Evans‐Mongeon
Texas Reliability Entity,
Inc.
Individual
Bradley Collard
X
X
X
X
37.
38.
Texas Reliability Entity, Inc.
Individual
Ryan Walter
Oncor Electric Delivery Company LLC
Tri‐State Generation and Transmission
Association, Inc.
40.
Individual
Michael P. Moltane
ITC
X
41.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
X
39.
Consideration of Comments: Project 2007‐17.2 | August 2013
10
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration:
Organization
Supporting Comments of “Entity Name”
Consumers Energy Co.
Consumers Energy Co.
Hydro One Networks Inc.
IESO and NPCC RSC
Lincoln Electric System
MRO NERC Standards Review Forum (NSRF)
Utility Services
NPCC Reliability Standrds Committee
South Carolina Electric and Gas
SERC PCS
Kansas City Power & Light
SPP ‐ Robert Rhodes
Ameren
We agree with the SERC Protection & Control Subcommittee (PCS) comments and include
them by reference.
Consideration of Comments: Project 2007‐17.2 | August 2013
11
1. In response to comments, the drafting team revised the previously‐posted draft of PRC‐005‐3 and the Supplementary Reference
and FAQ document. Do you agree with these changes? If not, please provide specific suggestions for improvement.
Summary Consideration:
The drafting team made no changes to PRC‐005‐3.
Several comments were offered on PRC‐005‐2. The drafting team reminded the commenters that changes to previously‐approved
content in PRC‐005‐2 are out‐of‐scope and prohibited by the SAR for this project.
Several commenters objected to the inclusion of maintenance of Automatic Reclosing within a Reliability Standard. The drafting
team explained that Automatic Reclosing is being added in response to a FERC directive from Order 758.
In response to comments regarding the objectives of PRC‐005‐3, the drafting team referred commenters to the referenced document,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”.
Several commenters requested an additional requirement be included in PRC‐005‐3 mandating that Balancing Authorities provide
Transmission Owners, Generator Owners, and Distribution Providers the information identifying the current largest single generating
unit in the Balancing Authority Area (described in Applicability 4.2.6), and notify those entities (within a specified time) when this
information changes. The SAR for this project does not permit the addition of functional entities to the Applicability section of this
standard; therefore, the drafting team is unable to make the requested change. The drafting team understands the request but
contends that such a requirement would be more appropriately included in a Reliability Standard applicable to Balancing Authorities;
consequently, the drafting team has added this issue to the NERC Issues Database for consideration when the pertinent Reliability
Standard is revised.
In response to assorted comments regarding the Applicablity 4.2.6 and the associated footnote, the drafting team added more
discussion to the Supplementary Reference and FAQ document in Section 2.4.1.
Organization
Yes or No
Oklahoma Gas & Electric
No
Question 1 Comment
1. In the draft Standard and the Supplementary Reference and FAQ document, a lot
of detail was deleted from the definition of Automatic Reclosing. The revised
definition no longer includes the phrase "but excluding breaker internal controls such
as anti‐pump and various interlock circuits." Does this imply that those components
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are now included in the definition of Automatic Reclosing? In reference to these
components, the Supplementary Reference and FAQ document (in section 15.8.1)
states that, "These components are not specifically addressed within Table 4, and
need not be individually tested. They are indirectly verified by performing the
Automatic Reclosing control circuitry verification as established in Table 4." The
Standard needs to be explicit on what is and is not required to be tested as part of an
entities PRC‐005 maintenance and testing program rather than leaving it open to
interpretation.
2. In 4.2.6.1 of the Applicability section of the draft Standard, reference is made to the
total installed gross generating capacity of a generating plant which is then compared
to the gross generating capacity of the largest BES unit in the Balancing Authority
Area. It would be helpful if the drafting team provided some examples (including
some that references how to address combined cycle units/plants) in the
Suppementary Reference document to help entities understand and properly apply
Section 4.2.6.1 of the Standard.
Response: Thank you for your comments.
1. The standard requires verification that Automatic Reclosing (defined as including two Components ‐ the reclosing relay and the
control circuitry associated with the reclosing relay), upon initiation, does not issue a premature closing command. All of the
referenced components would be indirectly verified by performing the Automatic Reclosing control circuitry verification
established in Table 4.
2. In response to your request, the drafting team provided additional discussion in Section 2.4.1 of the Supplementary Reference
and FAQ document.
ACES Standards Collaborators
No
(1) We find that the changes are non‐substantive and do not present a problem.
However, we continue to be concerned about modifying this standard when there is
another version pending before the Commission. We believe it will only cause
confusion. Given that this standard is historically one of the top ten most violated
standards and the most violated non‐CIP standard, industry does not need to be
burdened with further confusion that will only cause additional violations. One
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example of the confusion is the implementation plan of the proposed draft. If the
PRC‐005‐2 standard was already enforceable, the implementation plan could focus
only on auto‐reclosing which would avoid the confusion.
(2) Because there were no general feedback questions asked and there is no other
appropriate question to place our other concerns with the proposed standard, we are
inserting them here.
(3) The implementation plan creates confusion with dual conflicting parallel dates.
The confusion is understood by comparing PRC‐005‐2 implementation plan to the
PRC‐005‐3 implementation plan. For example, the implementation plan for PRC‐005‐2
requires the responsible entity to be at least 30 percent compliant on the first day of
the first calendar quarter 24 months following applicable regulatory approval for
maintenance activities with a three year interval. The PRC‐005‐3 implementation plan
is identical. Thus, if FERC approves PRC‐005‐2 such that is has an effective date of
June 1, 2014, the responsible entity will have to be 30 percent compliant with R3 and
R4 for equipment with three‐year interval maintenance cycles by July 1, 2016. If FERC
then approves PRC‐005‐3 such it has an enforceable date of September 1, 2015, the
responsible entity will have to be 30 percent compliant with R3 and R4 for equipment
with a three‐year interval maintenance cycles by October 1, 2017. Thus, there will be
two different conflicting dates for the 30 percent compliance level. Which applies? If
the second applies, this is like resetting the compliance date. Furthermore, there is
unnecessary confusion with the 30 percent compliant metric, as this could change
from the two different implementation plans if additional equipment is installed
during the implementation plan. There are too many compliance risks of having
implementation plans overlapping or coming into effect in a short amount of time.
This proposal mirrors the issues of the implementation plans with CIP version 4 and
CIP version 5. FERC granted an extension in order to allow responsible entities to
more efficiently utilize resources to transition to the next version. We, as an industry,
should learn from this experience and not rush to the next version of the standard
prematurely.
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(4) We disagree with the statement (second paragraph first sentence and first bullet)
in the general considerations section of the implementation plan that states the
responsible entities must be prepared to identify Automatic Reclosing components
during the transition from version 2 to version 3. While we agree that this ultimately
will be necessary at some point in the transition to prepare for the compliance date,
we are concerned that an auditor could interpret this implementation plan as
requiring the responsible entity to develop an inventory of Automatic Reclosing
components prior to the effective compliance date. A standard cannot retroactively
require actions to be completed prior to its effective date. This identification of
Automatic Reclosing components presents serious compliance issues and we
recommend striking it in its entirety.
(5) We disagree with the statement (second paragraph first sentence and second
bullet) in the general considerations section of the implementation plan that states
the responsible entities must be prepared to identify “whether each component has
last been maintained according to PRC‐005‐2 (or the combined successor standard
PRC‐005‐3), PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, PRC‐017‐0, or a combination
thereof”. We do not have an issue if this statement applies only to the Protection
System components because they have been under these standards for some time.
However, this statement could be viewed as applying to Automatic Reclosing
components and it should not because they have never been subject to any standard.
While most responsible entities will have maintained their Automatic Reclosing
components, they simply were not required to maintain them and, thus, the
documentation may not be sufficient to demonstrate prior maintenance activities.
Maintenance activities for Automatic Reclosing components are not required until
PRC‐005‐3 is enforceable.
(6) We do not understand why PRC‐005‐1b, PRC‐008‐0, PRC‐011‐0, and PRC‐017‐0
will not be retired for 156 months or 13 years. That is quite a long time for these
standards to be effective in parallel. This poses a potential for double jeopardy and
we recommend retiring these standards at the same time the new standard becomes
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enforceable.
(7) We find the language in section 3 of the implementation plan for R3 and R4
confusing. That section proposes to require the responsible entity to comply with R3
and R4 for 30 percent of the Protection System components that are subject to three‐
year maintenance intervals. However, this language “or, for generating plants with
scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage” is added as a caveat. We are unsure how to
interpret it. Does this mean that if a generator has three‐year maintenance interval
that 30 percent of its Protection System components must meet compliance at the
conclusion of the first succeeding maintenance outage or it is an exception and all of
its Protection System components must meet R3 and R4 compliance obligations by
the same date?
(8) Section 4.2.6.1 of the applicability section of the standard is inconsistent with the
proposed definition of the Bulk Electric System (BES) and may be inconsistent with
existing definitions that vary by region. Since Inclusion I2 includes the generator and
generator step up (GSU) transformer as part of the BES, what exactly would constitute
the BES bus? The low side bus of the GSU transformer, the high side bus or some
other location? All of these are part of the BES. This section needs further
clarification.
(9) Section 4.2.6.2 of the applicability section of the standard needs further
refinement. What would constitute one bus away from the generating plant? What
constitutes the plant? The electrical machine, turbine, GSU, and switchyard? What if
there is more than one switchyard? What if the switchyard is not on the immediate
property but short distance away? Some additional refinement would help to answer
these questions. We suggest utilizing the GSU as demarcation point to help clarify.
(10) The evidence retention section needs to clarify that the responsible entity is not
required to keep “documentation of the two most recent performances of each
distinct maintenance activity “during the initial implementation of the standard for
Automatic Reclosing components. This clarification will help avoid the problems that
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occurred with PRC‐005‐1 when auditors requested evidence from before the effective
date of the requirements. The bottom line is that a standard cannot be retroactive
and cannot compel evidence from before the effective date. This needs to be clear.
(11) The evidence retention period is excessively long, is inconsistent with the
Reliability Assurance Initiative (RAI), and is inconsistent with the Rules of Procedure.
Since some Automatic Reclosing component maintenance intervals are 12 years,
retaining the two most recent performances of each maintenance activity could result
in evidence retention periods of almost 36 years. Entire careers will be worked before
this evidence can be destroyed. Given the length of time, it is highly likely that
responsible entities will lose some of the documentation which will result in paper
violations that do nothing to support reliability. This is contrary to the RAI which is
trying move to a forward looking compliance model that provides reasonable
assurance of compliance. Furthermore, the evidence retention period is longer than
the six year audit cycle for TOs, GOs, and DPs which is inconsistent with section 3.1.4.2
of Appendix C ‐ Compliance Monitoring and Enforcement Program of the NERC Rules
of Procedures. This section is very clear that the evidence retention cannot exceed a
period prior to the last audit.
(12) We suggest that Table 4‐2(a) should be clarified that it only applies to those
Automatic Reclosing components that are at large generator plants or close to large
generator plants per applicability section 4.2.6.1 and 4.2.6.2 respectively. Otherwise,
there may be confusion when compliance and enforcement personnel look at the
table. They may view that it will apply to all Automatic Reclosing components that are
not an integral part of a Special Protection System (SPS) including those are not close
to large generators.
Response: Thank you for your comments.
1. The drafting team is acting in accordance with the schedule NERC provided to FERC which outlines the timeframes in which NERC
will respond to the directives of FERC Order 758 through the standards drafting process. Specifically regarding reclosing relays
(Footnote 37), FERC directed NERC to: “By July 30, 2012, NERC should submit to the Commission either the completed project
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2.
3.
4.
5.
6.
7.
8.
9.
Yes or No
Question 1 Comment
which addresses the remaining issues consistent with this order, or an informational filing that provides a schedule for how NERC
will address such issues in the Project 2007‐17 reinitiated efforts.” Providing the schedule for addressing both reclosing relays
and relays that do not respond to electrical quantities addressed this requirement of FERC Order 758
N/A
The implementation plan established under PRC‐005‐2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC‐005‐3. The Implementation Plan provided with this posting is for PRC‐005‐3 and carries forward
the implementation schedules contained in PRC‐005‐2. Compliance levels will be based upon applicable regulatory approvals of
PRC‐005‐2 and PRC‐005‐3 and their associated applicable components.
Per the implementation period established for Requirement R1, an entity has 12 months to modify its Protection System
Maintenance Program to include Automatic Reclosing and identify applicable Automatic Reclosing components. Identification of
applicable Automatic Reclosing components is necessary to establish the maintenance schedules for implementing Requirements
R3 and R4. The drafting team contends entities have sufficient time to establish a PSMP, identify the applicable components,
and follow the Implementation Plan.
The entity should follow the previous maintenance intervals (if any) for any specific components until that component is
addressed by PRC‐005‐3. As the transition is occurring, the entity should adjust its maintenance and testing schedules to
demonstrate that the required percentage of components meets the maintenance intervals given in the PRC‐005‐3 tables at each
of the percent compliant milestones given in its Implementation Plan.
For the Compliance Enforcement Authority to be assured of compliance, the drafting team contends that the Compliance
Enforcement Authority will need the data of the most recent performance of the maintenance, as well as the data of the
preceding one to validate that entities have been in compliance since the last audit (or currently since the beginning of
mandatory compliance). The retirement schedule of the aforementioned standards meets this intent.
For Requirements R3 and R4, generating plants with scheduled outage intervals exceeding two years must be 30% compliant at
the conclusion of the first maintenance outage. It should be noted that this extension does not apply for the 60% and 100%
thresholds.
The BES is a NERC defined term that is undergoing revisions and might contain regional variations. PRC‐005‐3 will be workable
regardless of how the BES is defined. If an element is a BES element and is located at a generating plant substation, it is included
per Section 4.2.6.1, and the requirements for Automatic Reclosing apply. See Section 2.4.1 in the Supplementary Reference and
FAQ document for more discussion.
The drafting team contends Applicability Section 4.2.6.2 is clear and is based upon the recommendations from the SAMS/SPCS
report. See Section 2.4.1 in the Supplementary Reference and FAQ document for more discussion.
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10. From the Implementation Plan, General Considerations: “For activities being added to an entity’s program as part of PRC‐005‐3
implementation, evidence may be available to show only a single performance of the activity until two maintenance intervals
have transpired following initial implementation of PRC‐005‐3.” The Evidence Retention section of the standard applies to
steady‐state performance of the standard after implementation.
11. For the Compliance Enforcement Authority to be assured of compliance, the drafting team contends that the Compliance
Enforcement Authority will need the data of the most recent performance of the maintenance, as well as the data of the
preceding one to validate that entities have been in compliance since the last audit (or currently since the beginning of
mandatory compliance). The drafting team has specified the data retention in the posted standard to establish this level of
documentation. This seems to be consistent with what auditors are expecting (per the drafting team’s experience), and is also
consistent with Compliance Process Bulletins 2011‐001 and 2009‐05. The entity is urged to assure that data is retained as
specified within the standard.
12. The drafting team contends the standard is clear in that the tables apply to only those components contained in Section 4.2
Facilities.
PPL NERC Registered Affiliates
No
1) There are currently two NERC approved projects filed at FERC (PRC‐005‐1.1b and
PRC‐005‐2). NERC should consider waiting to proceed with this project until the
current projects are ruled on and FERC provides further direction.
2) For 4.2.6, for reclosing capability, it is unclear what functionality is to be tested.
Please define.
3) For PRC‐005‐3 section 4.2.6.2, please provide the technical basis for this application
of the Standard. Specifically, this application states for Automatic Reclosing: “Applied
on BES Elements at substations one bus away from generating plants specified in
section 4.2.6.1 when the substation is less than 10 circuit miles from the generating
plant substation.” Please provide the technical basis/reasoning for the 10‐mile
criteria. At a recent North American Transmission Forum Workshop on Protection
System Maintenance Program it was implied that the 10 mile rule is for cases where a
generator has a short connection to another company’s substation. Please clarify if
this is the case.
4) For PRC‐005‐3 section R1, consider adding the following language that is used for
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PRC‐005‐1.1b “each Generator Owner that owns a generation or generator
interconnection Facility Protection System...” This is NERC‐approved language that
has been through the standards development process and has technical justification
through Project 2010‐07.
5) Please provide the technical basis for R1.1 which requires battery testing for DC
Supply Component Type Protection Systems to be time based.
6) Table 1‐2 of PRC‐005‐3 requires functional testing of non‐monitored
communication systems on a 4 month cycle. Please specify NERC’s criteria for the
functional testing (what attributes to be tested). Additionally, specifically define
monitoring criteria and data intervals for continuous monitoring of communications
systems (to see if check back (fail/no fail) monitoring is adequate).
7) This standard presents compliance documentation uncertainties for applicable
reclosing relays defined in Applicability Section 4.2.6.1 “Automatic Reclosing applied
on the terminals of Elements connected to the BES bus located at generating plant
substations where the total installed gross generating plant capacity is greater than
the gross capacity of the largest BES generating unit within the Balancing Authority
Area”. This standard now assumes that GO/TOs are going to coordinate and
document that they have contacted the BA to determine the largest unit in the area
and then determine if the reclosing relays are/are not applicable but does not
mention it in the measures. How much coordination and documentation is required
by a GO and its associated switchyards. Does the TO need to prove that the
generation facility does or does not exceed the largest BES unit? Does this become
part of a PRC‐001 requirement to coordinate protection systems?
Response: Thank you for your comments.
1) The drafting team is acting in accordance with the schedule NERC provided to FERC which outlines the timeframes in which NERC
will respond to the directives of FERC Order 758 through the standards drafting process.
2) This is defined in the PRC‐005‐3 tables 4‐1, 4‐2a, and 4‐2b of the proposed standard and clarified in the reference document
"Considerations for the Maintenance and Testing of Autoreclosing Schemes."
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3) As noted in the SAMS and SPCS study, premature autoreclosing has the potential to cause generating unit or plant shaft damage
or instability. The report noted that "transmission line impedance on the order of 1 mile away typically provides adequate
impedance to prevent generating unit instability and a 10 mile threshold provides sufficient margin."
4) Your comment refers to previously‐approved content. The SAR for this project explicitly limits the scope of this project to those
changes needed to address Automatic Reclosing. Changes such as you suggest are out‐of‐scope.
5) Your comment refers to previously‐approved content. The SAR for this project explicitly limits the scope of this project to those
changes needed to address Automatic Reclosing. These requirements are unchanged from PRC‐005‐2 and specific maintenance
practices and criteria are discussed in the Supplementary Reference and FAQ document for PRC‐005‐2.
6) Your comment refers to previously‐approved content. The SAR for this project explicitly limits the scope of this project to those
changes needed to address Automatic Reclosing. These requirements are unchanged from PRC‐005‐2 and specific maintenance
practices and criteria are discussed in the Supplementary Reference and FAQ document for PRC‐005‐2.
7) The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a
Reliability Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues
Database for consideration when the pertinent Reliability Standard is revised.
Pepco Holdings Inc & Affiliates
No
1) In section 4.2.6.1 the term “gross generating plant capacity” is used. We assume
this refers to nameplate MVA ratings. To avoid confusion as to what unit of capacity
(MVA or MW) is to be used to evaluate these criteria we suggest the phrase be
clarified as “gross generating plant capacity (in MVA)”.
2) NERC’s System Analysis and Modeling Subcommittee (SAMS) recommended
limiting the applicability of automatic reclosing within this standard to only those
installations that would impact the reliability of the BES. Section 4.2.6.1 uses criteria
based on the “gross generating plant capacity”. Neither the PRC‐005‐3 standard itself,
nor the Supplementary Reference and FAQ document explains how to calculate this
gross capacity number. Consider a generating plant that has a total of 600 MVA of
installed capacity connected to a 230kV bus. There are also units within the same
“power plant” with 200 MVA of capacity connected to a 69kV bus. The 230kV and
69kV busses are interconnected by an autotransformer. The “gross generating plant
capacity” is 800 MVA, however 200 MVA of this is connected below 100kV and is not
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considered BES generation. If it is not considered BES generation, then it should be
excluded from the calculation of gross plant capacity in Section 4.2.6.1, as the loss of
this generation would not directly affect the reliability of the BES.
3) In some switchyard arrangements generating units within the same power plant are
connected to separate switchyard busses that are not connected together. This may
be done for reliability reasons and to control fault current levels. In these situations,
the calculation of gross plant capacity in Section 4.2.6.1 should be based only on the
amount of generation directly connected to the individual bus, and not the total
amount in the plant.
4) The NERC SAMS review concluded that automatic reclosing mal‐performance
affects BES reliability when “inadvertent reclosing near a generating station subjects
the generation station to severe fault stresses”. The concern appears to be potential
shaft torque damage, or instability, of rotating machines to automatic reclosing mal‐
performance. That being the case, generation sources that are not subject to severe
fault stresses, such as inverter based generation, or static reactive sources (SVC’s,
capacitor banks, etc.) should not be included in the calculation of gross plant capacity.
However, since synchronous condensers are subject to the same fault stresses as
synchronous generators they should probably be included in the gross plant
generation calculation, providing they are interconnected at 100kV, or above.
5) To adequately address the concerns raised in the above sets of comments we
suggest Section 4.2.6.1 be re‐worded as follows to provide clarity and eliminate
confusion on how to evaluate this plant capacity calculation: “Automatic Reclosing
applied on the terminals of Elements connected to the BES bus located at generating
plant substations where the total installed gross generating plant capacity (in MVA)
connected to that bus is greater than the gross capacity (in MVA) of the largest BES
generating unit within the Balancing Authority Area.” In addition, a qualifying
footnote defining “gross generating plant capacity” needs to be added as follows:
“For application of 4.2.6.1 gross generating plant capacity is defined as the sum total
of the nameplate ratings, expressed in MVA, of all BES rotating machine generating
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units (including synchronous condensers) that are connected to a common BES
switchyard bus.” Also, specific examples showing how to calculate “gross generating
capacity” should be included in the Supplemental Reference document in order to
illustrate and clarity the issues described in the above comments. How will the
applicable functional entities be aware of the largest (or change in the largest) BES
generating unit within the BA area?
Response: Thank you for your comments.
1) Thank you for your comments. No change was made to the standard; however, the drafting team provided additional discussion
in Section 2.4.1 of the Supplementary Reference and FAQ document.
2) The intent was to prevent a loss of generation that exceeds the capacity of the largest unit in the Balancing Authority Area
regardless of the connected voltage levels. There are numerous scenarios possible and the drafting team contends that if the
resolution of a particular scenario isn’t clear from the Applicability Section, an entity should either maintain the Automatic
Reclosing pursuant to PRC‐005‐3 or perform studies to exclude the Automatic Reclosing maintenance (reference the footnote in
the Applicability Section).
3) There are numerous scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear
from the Applicability Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform
studies to exclude the Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
4) Damage to a generator is not the basis for determining the applicability of the Automatic Reclosing components; the loss of
generation capacity that exceeds the largest unit within the Balancing Authority Area is the basis. Since there are numerous
scenarios possible, the drafting team contends that if the resolution of a particular scenario isn’t clear from the Applicability
Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform studies to exclude the
Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
5) An entity is expected to coordinate with its Balancing Authority and agree on the unit of measure (MVA or MW) of the generation
facilities – consistency is required. Entities are required to remain compliant and to obtain the data necessary to meet
requirements.
Southern Company
No
1) We believe that there should be a Requirement for the BA to initially inform the
TOs and GOs in their area which units are in scope. Minimally, there must be a
requirement that the BA identify the ‘largest BES generating unit’ and inform all the
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TOs and GOs in their area.
2)Secondly, related to 1) above, there must be a requirement that the BA inform all
the TOs and GOs in their area when a change occurs related to the ‘largest BES
generating unit’.
Response: Thank you for your comments.
1 & 2) The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project.
The drafting team understands the request but contends that such a requirement would be more appropriately included in a
Reliability Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues
Database for consideration when the pertinent Reliability Standard is revised.
Colorado Springs Utilities
No
1.Concerning facilities, would a reliability based method of determining covered
facilities more likely better serve the reliability of the BES versus the generation based
cap method under 4.2.6?
2.With no standard requiring re‐closing relaying be in place, there will be a tendency
to disable all re‐closing relays to avoid facilities coming under this standard.
Response: Thank you for your comments.
1) The drafting team is following the recommendations provided by the technical experts on the NERC System Analysis and
Modeling Subcommittee and the System Protection and Control Subcommittee. They issued a joint technical document entitled
“Considerations for Maintenance and Testing of Autoreclosing Schemes” and it is posted on the PRC‐005‐3 project page for your
review.
2) The drafting team is responding to a FERC directive to include Automatic Reclosing in the maintenance standard.
ITC
No
1. 4.2.6 references a footnote 1 that is an exclusion. How can an exclusion be put
into a footnote? It should be up in the standard, not in a footnote.
2. Regarding 4.2.6.1 for generating plant substations that have generator outputs at
separate kV levels where the switchyards are not normally tied together are they
treated as separate generating plants? Same question for locations that have
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generator outputs where the switchyards are not directly tied together.
3. For a location that has a couple Balancing Authority Areas over it is the largest BES
generating unit determined by the largest Balancing Authority Area?
Response: Thank you for your comments.
1) The footnote is part of the Applicability section of the standard.
2) There are numerous scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear
from the Applicability Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform
studies to exclude the Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
3) Coordinated operations between Transmission Owners and Generator Owners and their associated Balancing Authorities are
required under other NERC Reliability Standards – TOP‐002‐2.1b. Entities are required to remain compliant and to obtain the
data necessary to meet requirements.
Liberty Electric Power
No
1. 4.2.6.1 uses the phrase "greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area" as one determinant for
inclusion of relays into the standard. However, generators do not have a wide
area view of the system, and cannot determine the gross capacity of the
largest BES generating unit. Does this value include all generation which could
trip simultaneously at a single generating location? All generation which is
connected through a single step‐up transformer? Further, changes outside of
the control of a generator could move relays in or out of the program. If
retirement of an asset lowers the gross capacity value of the largest BES
generating unit, would relays immediately be pulled into the program?
2. Finally, there is no requirement for the BA to provide the gross capacity value
to generation owners. The BA should be added to the list of covered entities,
with a requirement to provide to all entities in their balancing area notice of
the gross capacity of the largest generating unit once per calendar year, and
within 30 days of a change in this value.
3. Another section should be added to the standard to list the implementation
requirements for existing assets when a covered relay enters the program.
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Response: Thank you for your comments.
1. There are numerous scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear
from the Applicability Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform
studies to exclude the Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
2. The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a
Reliability Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues
Database for consideration when the pertinent Reliability Standard is revised.
3. The drafting team incorporated the revised “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area” into the body of the full Implementation Plan such that only a single
Implementation Plan now exists.
Manitoba Hydro
No
Although Manitoba Hydro will continue to maintain our “negative” vote for this
standard based on concerns from the PRC‐005‐2 version, we do offer the following
comments to the drafting team in regards to PRC‐005‐3:
(1) Table 1‐4(a), (c), (f) ‐ Manitoba Hydro suggests that the maintenance activity for
electrolyte level inspections would be more appropriately specified on intervals of six
calendar months, rather than on a four month basis. It is our experience that
maximum maintenance intervals of 6 months are adequate at addressing reliability.
Requiring four month intervals would be needlessly burdensome to industry without
achieving additional reliability benefit. Moreover, the maintenance activities which
require inspections to be completed every 18 months will oblige entities to make an
additional site visit every second year. In effect, entities are being asked to check
equipment (e.g. electrolyte levels) on month 16, return on month 18 to check
equipment components such as ohmic values, charge float voltage, etc, and then
required to return again on month 20 to check electrolyte levels, which is excessive.
Instead, Manitoba Hydro suggests a more manageable maximum maintenance
interval of 4 calendar months for these types of maintenance activities (station dc
supply voltage, electrolyte level and for unintentional grounds).
Consideration of Comments: Project 2007‐17.2 | August 2013
26
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comment.
Your comment refers to previously‐approved content. The SAR for this project explicitly limits the scope of this project to those
changes needed to address Automatic Reclosing and prohibits other changes as you suggest. The requirements are unchanged from
PRC‐005‐2. Specific maintenance practices and criteria are discussed in the Supplementary Reference and FAQ document.
Public Service Enterprise Group No
Automatic reclosing systems, except for those which are an integral part of an SPS, are
not part of Protection Systems that are designed and installed to detect and protect
the BES from damage from faults and to keep blackouts localized, i.e., prevent
cascades. Autoreclosing relays and systems are installed simply to automate an action
by a system operator to close a breaker which automatically tripped, and with one
specific possible exception, contribute very little to BES reliability. Besides the SPS,
the one possible exception may be in those areas where by virtue of the transmission
system configuration rapid reclosing of a tripped breaker is needed to minimize
stability issues. PSEG agrees that reclosing relays may be significant to that specific
circumstance, i.e., where rapid action is needed to avoid system instability. To
identify those specific locations and circumstances and limit the inclusion of such
relays to those where it is necessary, PSEG suggests that the drafting team
incorporate language similar to that in the Transmission Relay Loadability Standard
PRC‐023‐2 R6 which could be modified for PRC‐005‐3 to read as follows: “Each
Planning Coordinator shall conduct an annual assessment to determine the specific
locations/circuits in its Planning Coordinator area for which Transmission Owners,
Generator Owners, and Distribution Providers with automatic reclosing relays must
comply with the maintenance and testing requirements for such relays under this
standard.” The Planning Coordinator has the expertise and skills to make this
determination; many if not most BES asset owners do not.Power systems are
designed to deal with permanent faults, not temporary faults. The extra cost of
inclusion of many automatic reclosing relays in the maintenance and testing program
would yield little or no benefit to reliability of the BES. Only those defined as essential
by the Planning Coordinator should be included in this Standard.
Consideration of Comments: Project 2007‐17.2 | August 2013
27
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments.
FERC Order 758 directed that maintenance of reclosing relays that affect the reliable operation of the Bulk Power System be
addressed. PRC‐005‐3 addresses this directive and when approved, will supersede PRC‐005‐2. Furthermore, PRC‐005‐3 follows the
recommendations included in the SAMS/SPCS technical document “Considerations for Maintenance and Testing of Autoreclosing
Schemes.”
Consumers Energy
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007‐17.2
Protection System Maintenance and Testing ‐ Phase 2 (Reclosing Relays) PRC‐005‐3
since the standard does not address how each entity is expected to obtain the
required information “the gross capacity of the largest BES generating unit with the
Balancing Authority Area” (in section 4.2.6.1) and know when it changes.
Response: Thank you for your comments.
The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Consumers Energy Co.
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007‐17.2
Protection System Maintenance and Testing ‐ Phase 2 (Reclosing Relays) PRC‐005‐3
since the standard does not address how each entity is expected to obtain the
required information “the gross capacity of the largest BES generating unit with the
Balancing Authority Area” (in section 4.2.6.1) and know when it changes.
Response: Thank you for your comments.
The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Consideration of Comments: Project 2007‐17.2 | August 2013
28
Organization
Yes or No
Western Area Power
Administration
No
Question 1 Comment
1. Further clarification and definition is required regarding the application of the
standard to “premature” closing. Specifically, what is the definition of
“premature” and why does the standard not refer to inadvertent or incorrect auto
reclosing.
2. Facilities Section 4.2.6.2 applies to automatic reclosing applied on the terminals of
all BES Elements at substations one bus away from generating plants specified in
Section 4.2.6.1 when the substation is less than 10 circuit miles from the
generating plant substation. This Section should be clarified and should not
include BES elements at those substations connected at a different voltage than
the incoming generation circuit. The impedance of any transformation should
represent sufficient isolation.
3. It should be clarified that dc control circuitry and power circuit breaker close coils
are only included with automatic reclosing that is an integral part of a SPS.
Response: Thank you for your comments.
1. “Premature” means “occurring or existing before the normal or expected time”. The concern from the SAMS report is in regard
to premature reclosing, not lack of reclosing or reclosing with longer than designed setting timeframe.
2. The drafting team followed the recommendations included in the “Considerations for Maintenance and Testing of Autoreclosing
Schemes” and has provided additional language in the Supplementary Reference and FAQ document in Section 2.4.1. There are
numerous scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear from the
Applicability Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform studies to
exclude the Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
3. The drafting team contends that Tables 4‐2(a) and 4‐2(b) are clear: The control circuitry up to and including the close coil is
included for circuit breakers involved in SPS schemes (Table 4‐2(b)). If not part of an SPS, it is only necessary to verify that the
control circuitry does not cause a premature close (Table 4‐2(a)).
SPP Standards Review Group
No
1. In the definition of Automatic Reclosing a goodly amount of detail has been
deleted from the definition. Does the excluded portion of the definition,
specifically breaker internal controls such as anti‐pump and various interlock
circuits still fall under the standard? The reference document implies that they do,
Consideration of Comments: Project 2007‐17.2 | August 2013
29
Organization
Yes or No
Question 1 Comment
but the revised wording is not clear to us.
2. In 4.2.6.1 reference is made to the total installed gross generating capacity of a
generating plant which is then compared to the gross generating capacity of the
largest BES unit in the Balancing Authority Area. Shouldn’t the reference to the
largest unit also state the installed gross capacity of the unit to prevent any
confusion? Also, in selecting to use gross generation numbers, we wonder if
consideration was given to generation values used in other standards such as BAL‐
002 and BAL‐003 which tend to lean toward net generation values rather than
gross.
3. In the Supplementary Reference and FAQ document we suggest replacing the term
‘supervisor’ on Page 92 in Section 15.8.1 FAQ in the 7th line of the 1st paragraph in
the response to the 2nd question with ‘supervision’. The sentence would then
read ‘...applicability of associated supervision/conditional logic and the...’.
Response: Thank you for your comments.
1. The standard requires verification that Automatic Reclosing (defined as including two Components a) Reclosing relay and b)
Control circuitry associated with the reclosing relay) upon initiation, does not issue a premature closing command. All of the
components mentioned would be indirectly verified by performing the Automatic Reclosing control circuitry verification as
established in Table 4.
2. The Applicability section 4.2.6.1 is consistent with the recommendations from the SAMS/SPCS report. See Section 2.4.1 in the
Supplementary Reference and FAQ document for more discussion. An entity is expected to coordinate with its Balancing Authority
and agree on the unit of measure (MVA or MW) of the generation facilities – consistency is required.
3. The drafting team made the suggested change.
MRO NERC Standards Review
Forum (NSRF)
No
1. Plase clarify what is meant by “BES elements at substations one bus away from
generating plants”. How is the one bus criterion applied at a generating station
with power transformation and multiple voltages? The use of the words substation
and “one bus away” leaves the definition open to interpretation when a plant is
connected at one voltage class and there are reclosing relays at another voltage
class. The higher or lower voltage class bus could be read as “one bus away” and
Consideration of Comments: Project 2007‐17.2 | August 2013
30
Organization
Yes or No
Question 1 Comment
yet at the same substation. It may be necessary to speak in terms of either
substations or electrical busses. It may also be necessary to define how a different
voltage class bus should be treated. Could a large power transformer between
voltage classes be equivalent to 10 circuit miles of impedance? Was the reclosing
only meant to apply at the same voltage class?
Response: Thank you for your comments.
The drafting team followed the recommendation of the “Considerations for Maintenance and Testing of Autoreclosing Schemes”
and has provided additional language in the Supplementary Reference and FAQ document in Section 2.4.1. There are numerous
scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear from the Applicability
Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform studies to exclude the
Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
American Electric Power
No
Regarding 4.2.6.2 in the Facilities section, the verbiage used suggests that substations
that are one bus away, but connected by a transformer instead of a line, would be in
scope. This would seem technically inappropriate, as a transformer would typically
have a higher impedance than 10 miles of line and therefore premature reclosing at
these substations should not affect generators one bus away in these cases. If such
substations were to be included, it would unnecessarily bring into scope many more
reclosing relays than intended by FERC Order No. 758.AEP envisions voting affirmative
on this proposed standard if our concerns regarding scope are eventually addressed.
Response: Thank you for your comments.
The drafting team followed the recommendation of the “Considerations for Maintenance and Testing of Autoreclosing Schemes”
and has provided additional language in the Supplementary Reference and FAQ document in Section 2.4.1. There are numerous
scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear from the Applicability
Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform studies to exclude the
Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
Independent Electricity System
No
The IESO contends that the analysis required by the Footnote 1 is out of the scope of
Consideration of Comments: Project 2007‐17.2 | August 2013
31
Organization
Yes or No
Operator
Question 1 Comment
PRC‐005‐3, which is to document programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the BES so that they are kept in working
order. In addition, the analysis required by the Footnote 1 is vague and difficult to
assess compliance. In the IESO’s view, contingencies and related tests performed in
transient simulations should be defined in the planning standards (eg. the TPL
standards), instead of PRC‐005‐3 which is drafted for maintenance purposes. We
suggest removing the Footnote 1 from the draft standard, or in case it is retained it
should be revised to address the aforementioned concerns.
Response: Thank you for your comments.
The information contained within the footnote is to allow the responsible entity to determine which reclosing systems they may
exclude. The data required to determine exclusion is to be obtained by the owner. It is the responsibility of the Transmission Owner,
Generator Owner, and Distribution Provider with Automatic Reclosing to apply the standard and to perform the necessary
evaluations to exclude otherwise‐applicable Automatic Reclosing from their PSMP if they desire to do so.
Dominion
No
The drafting team did not address concerns relative to how an entity could determine
the gross capacity of the largest BES generating unit within the Balancing Authority
Area. Dominion suggests the drafting team include a requirement that the BA post or
make such information available to all entities in its area. The drafting team did not
address concerns that only planning entities are typically afforded access to the
models or information, or have the technical skills necessary to be able to make the
determination necessary to allow the exclusion included in footnote 1.
Response: Thank you for your comments.
The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
American Transmission
No
The selection criteria proposed to identify the reclosing relays that affect the
Consideration of Comments: Project 2007‐17.2 | August 2013
32
Organization
Yes or No
Company, LLC
Question 1 Comment
reliability of the Bulk Electric System remains unclear. Please clarify what is meant by
“BES elements at substations one bus away from generating plants”. How is the one
bus criterion applied at a generating station with power transformation and multiple
voltages?
Response: Thank you for your comments.
The drafting team followed the recommendation of the “Considerations for Maintenance and Testing of Autoreclosing Schemes”
and has provided additional language in the Supplementary Reference and FAQ document in Section 2.4.1. There are numerous
scenarios possible and the drafting team contends that if the resolution of a particular scenario isn’t clear from the Applicability
Section, an entity should either maintain the Automatic Reclosing pursuant to PRC‐005‐3 or perform studies to exclude the
Automatic Reclosing maintenance (reference the footnote in the Applicability Section).
North American Generator
Forum Standards Review Team
No
This standard presents compliance documentation uncertainties for applicable
reclosing relays defined in Applicability Section 4.2.6.1 “Automatic Reclosing applied
on the terminals of Elements connected to the BES bus located at generating plant
substations where the total installed gross generating plant capacity is greater than
the gross capacity of the largest BES generating unit within the Balancing Authority
Area”. This standard now assumes that GO/TOs are going to coordinate and
document that they have contacted the BA to determine the largest unit in the area
and then determine if the reclosing relays are/are not applicable but does not
mention it in the measures. How much coordination and documentation is required
by a GO and its associated SWYDs TO to prove that the generation facility does or
does not exceed the largest BES unit? Does this become part of a PRC‐001
requirement to coordinate protection systems?
Response: Thank you for your comments.
The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Consideration of Comments: Project 2007‐17.2 | August 2013
33
Organization
Yes or No
Tri‐State Generation and
Transmission Association, Inc.
No
Question 1 Comment
1. Tri‐State Generation and Transmission Association, Inc. finds that Table 4‐1 is too
inclusive and should include a restriction for only automatic reclose
relays/functions that are required for system stability, with a list of which those
should be as per SAMS, such as SPS and near generation. Table 4‐1, as written,
captures more equipment than is necessary, creating an undue administrative
burden with little, to no, benefit to the reliability of the BES. Adding a compliance
liability for reclosing relays that do not impact system stability could lead to
industry removing many of the reclosing relays used for expeditious restoration.
This does not improve system reliability. Also, since the majority of reclosing
functions utilizing microprocessor relays reside within the microprocessor
protective relay, the documentation for this testing will be included within
documentation already required and provided under Table 1‐1. To provide a
separate list and documentation for all BES microprocessor reclosing functions will
create an undue administrative burden on industry with little to no value to the
BES. Further, we recommend the applicability of reclosers is changed to “reclosers
identified by the entity’s selection criteria to be critical to the operation of the BES
per its Maintenance and Testing Program” to better align with FERC order 758
where FERC recommends “selection criteria should be used to identify reclosing
relays that affect the reliability of the Bulk‐Power System”.
2. Tri‐State suggests that Table 4‐2(a), Control Circuitry Associated with Reclosing
Relays that are NOT an Integral Part of an SPS, be removed in its entirety or a
maintenance activity specific to the circuitry be defined. The maintenance activity
required in Table 4‐2(a) is not a maintenance activity that verifies the control
CIRCUITRY. A close “command” is external to the hardware circuitry. Whether or
not that command occurs, does not confirm the functionality of the close circuitry
hardware. The timing test for a reclosing function is also usually included within
the testing of the protective relay, which is part of Table 1‐1 and Table 4‐1, making
this table slightly redundant to what already exists. A definition of “premature”,
giving specific tolerances, will also be required, if kept within the text, to
understand at what point a test would fail or a result would be viewed as “non‐
Consideration of Comments: Project 2007‐17.2 | August 2013
34
Organization
Yes or No
Question 1 Comment
compliant”. Any test for a microprocessor instantaneous reclose would fail this
requirement, as the close command is already present at the beginning of the
sequence, hence being “premature”. A PASS test result showing the reclose
command was initiated within the tolerance of the relay but prior to the setting
could be viewed as “premature” and be interpreted as “non‐compliant”. A FAIL
test result showing the relay closed well out of the manufacturer tolerance but
after the setting would be viewed as “compliant”. If the text and Table remain,
the statement: “Verify that Automatic Reclosing, upon initiation, does not issue a
premature closing command to the close circuitry” should be changed to, “Verify
that the close circuitry operates per engineering settings, and not sooner than
(tolerance) of the setting.”
Response: Thank you for your comments.
1. The drafting team followed the recommendations included in the SAMS/SPCS technical document “Considerations for
Maintenance and Testing of Autoreclosing Schemes” for determining the applicable reclosing relays.
2. The drafting team contends that Tables 4‐2(a) and 4‐2(b) are clear: The control circuitry up to and including the close coil is
included for circuit breakers involved in SPS schemes (Table 4‐2(b)). If not part of an SPS, it is only necessary to verify that the
control circuitry does not cause a premature close (Table 4‐2(a)).
Cleco
No
We do not believe reclosing relays are protective devices and therefore are not
subject to this level of oversight. Second, the strongest justification was that if the
relay failed to operate correctly and reclosed instantaneously, the generator would be
subject to additional fault duty. We have not seen such a failure and do not see the
justification for including reclosing relays or restoration devices in a Protection System
Maintenance & Testing Standard. Major storm events near the station or breakers
failing to latch are far more likely to cause sequential faults.
Response: Thank you for your comments.
FERC Order 758 directed that maintenance of reclosing relays that affect the reliable operation of the Bulk Power System be
addressed. PRC‐005‐3 addresses this directive, and follows the recommendations included in the SAMS/SPCS technical document
Consideration of Comments: Project 2007‐17.2 | August 2013
35
Organization
Yes or No
Question 1 Comment
“Considerations for Maintenance and Testing of Autoreclosing Schemes.”
Texas Reliability Entity, Inc.
No
We feel that the proposed maintenance activities in tables 4‐1 and 4‐2 do not
necessarily address all of the typical failure modes of reclosing relays and control
circuitry associated with them and offer the following comments:
1) Definition of Automatic Reclosing: Is it the drafting team’s intention that “Control
circuitry associated with the reclosing relay” includes a separate sync check relay that
may be used in the reclosing scheme? The definition is not clear and the drafting
team may want to clarify.
2) Table 1‐3: The drafting team may want to consider adding an activity to verify
voltage signals are provided for reclosing relay sync check functions.
3) Table 4‐2(a) and 4‐2(b): The drafting team may want to consider including activities
to verify that auxiliary relays in the reclosing scheme (i.e. bus differential or breaker
failure lockout relays) properly inhibit reclosing. The drafting team may also want to
consider including activities to verify sync check functions depending on the system
design (i.e. hot bus‐hot line, hot bus‐dead line, etc.). These two activities are
necessary to verify that the reclosing scheme will not issue a reclose signal when it is
not desired. Table 4‐2(b): Suggest rewording the 2nd block to say “Verify all paths of
the control circuits ***including all auxiliary relays*** associated with Automatic
Reclosing...”
Response: Thank you for your comments.
1. The drafting team contends that Tables 4‐2(a) and 4‐2(b) are clear: The control circuitry up to and including the close coil is
included for circuit breakers involved in SPS schemes (Table 4‐2(b)). If not part of an SPS, it is only necessary to verify that the
control circuitry does not cause a premature close (Table 4‐2(a)).
2. Sync check relays are not in scope of PRC‐005‐03. See the SAMS/SPCS report.
3. The drafting team is following the recommendations provided by the technical experts on the NERC System Analysis and Modeling
Subcommittee and the System Protection and Control Subcommittee. They issued a joint technical document entitled
“Considerations for Maintenance and Testing of Autoreclosing Schemes” and it is posted on the PRC‐005‐3 project page for your
Consideration of Comments: Project 2007‐17.2 | August 2013
36
Organization
Yes or No
Question 1 Comment
review.
SERC Protection and Controls
Subcommittee
Yes
1) Please provide FAQ examples to clarify the meaning of ‘total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit’. Our take is the gross MVA for FAC‐008 would be appropriate. But
there are several MOD standards, including some pending FERC approval, that will
prove MW and MVAR ‘capability’ not ‘capacity’.
2) We request that the drafting team modify the FAQ 2.4.1 to include “typically IEEE
Device No. 79” in referring to the Automatic Reclosing relay because this helps clarify
the scope. Begin the answer with “Yes. Automatic Reclosing includes reclosing relays
(typically IEEE Device No. 79) and the associated dc control circuitry.”
Response: Thank you for your comments.
1. In response to your request, the drafting team provided additional discussion in Section 2.4.1 of the Supplementary Reference and
FAQ document.
2. Automatic Reclosing may be either a function imbedded in other devices or a stand‐alone device. The drafting team does not
believe that the IEEE function number should be referenced.
Tacoma Power
Yes
Additional Comments‐
1. In the definition of a PSMP, captialize ‘components’.
2. In the definition of a PSMP (including Supplementary Reference and FAQ
document), capitalize ‘automatic reclosing’.
3. In the Implementation Plan, change “The existing standard PRC‐005‐2 shall be
retired at midnight of the day immediately prior to the first day of first calendar
quarter...” to “The existing standard PRC‐005‐2 shall be retired at midnight of the day
immediately prior to the first day of the first calendar quarter...”
Response: Thank you for your comments.
1. The drafting team cannot capitalize “components” in the definition of Protection System Maintenance Program (PSMP) because
Consideration of Comments: Project 2007‐17.2 | August 2013
37
Organization
Yes or No
Question 1 Comment
PSMP is a NERC Glossary Term.
2. The drafting team cannot capitalize “automatic reclosing” in the definition of Protection System Maintenance Program (PSMP)
because PSMP is a NERC Glossary Term.
3. The drafting team made the suggested addition.
Duke Energy
Yes
1. Duke Energy requests additional information regarding the Footnote 1
exclusion provision. As written, it is unclear as to what exactly is needed to
provide demonstration for this provision, as well as the frequency of the
demonstration necessary to remain compliant. For example, if an entity
performs an analysis to prove that the exclusion was applicable to a specific
Automatic Reclosing Relay, would the entity need to run another analysis ever
again, or would an analysis only need to be done if there was a change to the
Balancing Authority Area’s system or the BES?
2. Also Duke Energy suggests that because Footnote 1 effectively acts as an
exclusion, that the drafting team consider placing the Footnote in the standard
itself.
Response: Thank you for your comments.
1. The drafting team contends that a dynamic study of some sort would be necessary to demonstrate the exclusion of the
automatic relaying equipment. As you suggest, re‐evaluation would be required if system changes dictate.
2. The footnote is part of the Applicability Section of the standard.
Occidental Chemical Corp.
(Ingleside Cogeneration LP)
Yes
1. Ingleside Cogeneration agrees with the distinctions that the project team has
made to determine which automatic reclosing components may pose a risk to the
BES, and therefore should be subject to PRC‐005‐3. Clearly those that are
incorporated in an SPS have a direct reliability impact. However, it is reasonable
to limit applicable to reclosing systems that reside at or near significant generation
facilities.
2. We also agree that an exclusion should be allowed wherever the relay owner can
demonstrate that the generator protection scheme is configured to withstand a
Consideration of Comments: Project 2007‐17.2 | August 2013
38
Organization
Yes or No
Question 1 Comment
Fault time frame of twice the normal clearing time without severing the Facility
from the BES. This is a very conservative risk threshold and properly focuses
compliance resources on the most prevalent threats to BES performance.
3. Lastly, the limits of the control circuitry functionality testing are also appropriate.
The prior version of PRC‐005‐3 included testing through the breaker trip coils ‐
which may also inadvertently lock out other ancillary functions. Since the only
reliability concern is that the reclosing relay will misoperate in a manner that will
result in a premature closing signal, it is appropriate that the functional test
required by NERC focuses only on that point.
Response: Thank you for your comments and support.
ReliabilityFirst
Yes
ReliabilityFirst votes in the affirmative because the modifications to this standard
further establishes minimum maintenance activities for Automatic Reclosing
Component Types and the maximum allowable maintenance intervals. ReliabilityFirst
offers the following comments for consideration:
1. Table 4‐2(a) and 4‐2(b) ‐ ReliabilityFirst seeks the technical justification for the
maximum maintenance interval of 12 years for unmonitored control circuitry
associated with Automatic Reclosing.
2. Applicability section 4.2.6.1 ‐ ReliabilityFirst recommends adding the term
“nameplate rating” to clarify which generating plants are required have Automatic
Reclosing applied. Without this clarifier included, the term “total installed gross
generating plant capacity” is subject to interpretation. For example, a plant may have
multiple different values for its gross generating plant capacity but a plant will always
have one static nameplate rating. The term “nameplate rating” is also consistent with
the new NERC BES definition language.
Response: Thank you for your comments.
1. PRC‐005‐3 uses the same interval for ‘Protection System’ Components and the drafting team contends that it is likewise
appropriate for ‘automatic reclosing.’
Consideration of Comments: Project 2007‐17.2 | August 2013
39
Organization
Yes or No
Question 1 Comment
2. The drafting team contends the Applicability Section 4.2.6.1 is consistent with the recommendations from the SAMS/SPCS report.
See Section 2.4.1 in the Supplementary Reference and FAQ document for more discussion.
Xcel Energy
Yes
We are supportive of the changes made. But we do have two additional comments:
a. The inclusion of Table 4‐2(b) in PRC‐005‐3 raises the concern of where this testing
would have been required in PRC‐005‐2 and raises uncertainty about the drafting
team's intentions for the testing requirements for all the various possibilities for
actuation of SPS mitigating devices. We were under the impression that row 1 of
Table 1‐5 in PRC‐005‐2 required 6 year verification of trip coils or actuators of circuit
breakers or other SPS mitigating devices. What if an SPS calls for the closure of a
normally open breaker and that close signal is accomplished via some means other
than a reclosing relay? Where would the testing of such a breaker closure be required
by PRC‐005‐2 or PRC‐005‐3? The way PRC‐005‐3 Table 4‐2(b) is phrased it would
appear that trip coil operations for circuit breakers in protection systems or SPS's
would be required per Table 1‐5, row 1 and that close coils that are parts of reclosing
schemes are required per tested by Table 4‐2(b), row 1, but there does not appear to
be testing requirements for any other SPS mitigating devices such turbine runbacks,
closure of normally open breakers, disconnect operators, etc. Please clarify testing
requirements for SPS mitigating devices outside of breaker trip coils (Table 1‐5, row 1)
and close coils as utilized in SPS reclosing schemes (Table 4‐2(b)) ‐ e.g. turbine throttle
valve runback, LTC blocking or enabling, closure of normally open breakers, MOD
operation, etc., etc. This appears to be a reliability gap in both PRC‐005‐2 and PRC‐
005‐3.
b. The applicability of reclosing to the Generator Owner & Transmission Owner is
dependent upon the GO & TO knowing the characteristics of the Balancing Authority.
GOs & TOs do not have this knowledge. There should be an obligation of the BA to
inform (and update as needed) the GO and TO of the gross MW value of the largest
unit in the BA footprint (or determine the appropriate entity to update the GO & TO).
This could be accomplished by adding BA’s as an applicable entity to PRC‐005‐3 and
adding a requirement for this notification of TO’ s and GO’s by the BA to PRC‐005‐3.
Consideration of Comments: Project 2007‐17.2 | August 2013
40
Organization
Yes or No
Question 1 Comment
Alternatively, the applicable entities for PRC‐005‐3 could be left as is and the
requirement for BA’s to notify TO’s and GO’s could be accomplished by adding a new
requirement to a more appropriate standard.
Response: Thank you for your comments.
a. PRC‐005‐3 only deals with control circuits and relays associated with automatic reclosing. All other equipment is already covered
in the third row of Table 1‐5 Component Type ‐ Control Circuitry Associated With Protective Functions Excluding distributed UFLS
and distributed UVLS (see Table 3).
b. The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Northeast Power Coordinating
Council
Yes
PacifiCorp
Yes
City of Tallahassee
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
Oncor Electric Delivery
Company LLC
Yes
Consideration of Comments: Project 2007‐17.2 | August 2013
41
2. In response to comments, the drafting team developed an “Implementation Plan for Newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area” Do you agree with this additional Implementation Plan?
If not, please provide specific suggestions for improvement.
Summary Consideration:
Numerous commenters disagreed with the implementation period specified in the “Implementation Plan for Newly identified Automatic
Reclosing Components due to generation changes in the Balancing Authority Area” stating that it was too short to accommodate the
potential number of newly identified Automatic Reclosing Components that could become applicable nor did it provide enough time for
potential outage coordination(s) necessary to perform the required maintenance. Upon reconsideration, the drafting team agreed that
the proposed implementation schedule for newly identified Automatic Reclosing Components was inappropriate and could potentially
jeopardize reliability by forcing entities to take unscheduled outages to become compliant. The drafting team deemed three years to be
sufficient to avoid the reliability concerns and permit entities to implement maintenance in a manner that would be sustainable in the
long‐term.
In response to comments, the drafting team incorporated the “Implementation Plan for Newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area” into the full Implementation Plan to consolidate the
implementation documents.
In response to a comment, the drafting team inserted the jurisdictional pro‐forma language where it had been inadvertently left out of
the Implementation Plan. Additionally, NERC will file the errata change with the applicable regulatory authorities as necessary for the
PRC‐005‐2 Implementation Plan.
To avoid confusion, the drafting team modified paragraph 4 of the Background section to remove the references to the implementation
timing. The timing is already comprehensively addressed in the implementation plan for each requirement.
Organization
Yes or No
Tri‐State Generation and
Transmission Association, Inc.
No
Question 2 Comment
"Prior to the end of the following calendar year" is a very ambiguous implementation
plan and could require entities to be compliant anywhere between 12 and 24 months.
TSGT recommends that the implementation period state 18 months from the first day
of the quarter following component identification.
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
ACES Standards Collaborators
No
(1) We agree with the need for the additional implementation plan but find it
confusing. First, we think that the compliance date should be identified as some
interval after the commercial in‐service date of the change in generation or the official
retirement date. Otherwise, there could be confusion in which year the newly
applicable Automatic Reclosing components must be compliant. Consider a new unit
begins testing on December 1, 2013 and goes commercial January 31, 2014. One
could interpret the language in the implementation plan to require the maintenance
activities to be completed by December 31, 2014 or December 31, 2015.
(2) To avoid the confusion that occurred with PRC‐005‐1, the implementation plan
should state very clearly that the initial maintenance activities must be performed by
the compliance date and that no evidence of prior maintenance activities is required.
In essence, the compliance date established in this implementation plan due to
changes in generation and the overall implementation plan should be very clear that
the compliance date established in these plans is the start of the initial interval. To
allow the interval to start before the compliance date would be equivalent to making
the standard retroactive.
Response: Thank you for your comments.
1. The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due
to generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan
to consolidate the implementation documents.
2. The Implementation Plan already includes several attributes that address your concern. First, in the Background, the
Implementation Plan states, “For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those entities to be immediately
Consideration of Comments: Project 2007‐17.2 | August 2013
43
Organization
Yes or No
Question 2 Comment
compliant with the new activities or intervals. Further, entities should be allowed to become compliant in such a way as to
facilitate a continuing maintenance program.” Also in the Background, the Implementation Plan states “Entities that have
previously been performing maintenance within the newly specified intervals may not have all the documentation needed to
demonstrate compliance with all of the maintenance activities specified.” In the General Consideration, the Implementation Plan
states, “For activities being added to an entity’s program as part of PRC‐005‐3 implementation, evidence may be available to
show only a single performance of the activity until two maintenance intervals have transpired following initial implementation
of PRC‐005‐3.” Finally, in the specific implementation for Requirements R3 and R4 (reflecting the other quoted text), compliance
is intended to address the first performance of the respective activities within the associated intervals.
SERC Protection and Controls
Subcommittee
No
1) We prefer that maintenance for newly identified Automatic Reclosing Components
be completed within 3 calendar years. This is more consistent with the phased in
approach that applies to the overall implementation.
2) We prefer a single document with the implementation plan; please combine the 2
documents.
The comments expressed herein represent a consensus of the views of the above‐
named members of the SERC EC Protection and Control Subcommittee only and
should not be construed as the position of SERC Reliability Corporation, its board, or
its officers.
Response: Thank you for your comments.
1 and 2) The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area.” The document was also incorporated into the full
Implementation Plan to consolidate the implementation documents.
PPL NERC Registered Affiliates
No
1. Regarding the implementation plan for this project, the PPL NERC Registered
Affiliates are concerned with the following: “For Automatic Reclosing Component
maintenance activities with maximum allowable intervals of twelve (12) calendar
years, as established in Table 4: The entity shall be at least 30% compliant on the first
day of the first calendar quarter sixty (60) months following applicable regulatory
approval of PRC‐005‐3.” This would require two cycles of 12‐year maintenance in five
Consideration of Comments: Project 2007‐17.2 | August 2013
44
Organization
Yes or No
Question 2 Comment
years for 30% of your affected equipment. We recommend that the implementation
plan be changed to require that 100% of the affected relays have one maintenance
performed by 144 months from the implementation date of the standard.
2. The implementation plan states:”For activities being added to an entity’s program
as part of PRC‐005‐3 implementation, evidence may be available to show only a single
performance of the activity until two maintenance intervals have transpired following
initial implementation of PRC‐005‐3.”However, If there is no specific ‘bookend’
required, and the cycle is truly a 12‐year cycle, no evidence of testing or maintenance
could be required prior to 144 months from the enforcement date of the standard;
but the proposed implementation plan requires the work at 36 months, 60 months,
and 84 months, which is short of a 12‐year cycle.
Response: Thank you for your comments.
Your comments appear to refer to the initial Implementation Plan, rather than the “Implementation Plan for Newly Identified
Automatic Reclosing Components due to generation changes in the Balancing Authority Area”.
1. The premise presented in your comment is incorrect. The Implementation Plan establishes expectations for performance of the
initial maintenance under the standard. After the initial performance of the maintenance, the entity is expected to perform
ongoing maintenance according to the intervals in Table 4.
2. The statement to which you refer is intended to clarify that auditors should not expect evidence of multiple performances of the
maintenance until two full intervals have transpired. The majority of industry agrees with the phased‐in approach for
implementing the maintenance requirements.
North American Generator
Forum Standards Review Team
No
1. Regarding the implementation plan for this project, the SRT is concerned with the
following: “For Automatic Reclosing Component maintenance activities with
maximum allowable intervals of twelve (12) calendar years, as established in Table
4:The entity shall be at least 30% compliant on the first day of the first calendar
quarter sixty (60) months following applicable regulatory approval of PRC‐005‐3.” This
would require two cycles of 12‐year maintenance in five years for 30% of your
affected equipment. We recommend that the implementation plan be changed to
require that 100% of the affected relays have one maintenance performed by 144
Consideration of Comments: Project 2007‐17.2 | August 2013
45
Organization
Yes or No
Question 2 Comment
months from the implementation date of the standard.
2. The implementation plan states:”For activities being added to an entity’s program
as part of PRC‐005‐3 implementation, evidence may be available to show only a single
performance of the activity until two maintenance intervals have transpired following
initial implementation of PRC‐005‐3.”However, If there is no specific ‘bookend’
required, and the cycle is truly a 12‐year cycle, no evidence of testing or maintenance
should be required prior to 144 months from the enforcement date of the standard;
but the proposed implementation plan requires the work at 36 months, 60 months,
and 84 months, which is obviously short of a 12‐year cycle.
A Compliance Enforcement Authority could apply this in the following manner:Entity Y
has four reclosing relays, all tested and installed on August 1, 2004. The ne PRC‐005
Standard becomes effective on July 1, 2014. On August 2, 2014 entity Y could be
found in violation if one of the four relays has not gone through the new 12‐year
required cycle. If the language was changed to 100% compliance by 144 months, with
all the earlier steps eliminated, it would work. Specific language needs to be in place
noting that no evidence shall be required for any testing prior to the enforcement
date, and the 12‐year clock starts on that day. The following change would need to be
made also: “For activities being added to an entity’s program as part of PRC‐005‐3
implementation, evidence may be available to show only a single performance of the
activity until 288 months following the enforcement date of PRC‐005‐3.”
Response: Thank you for your comments.
Your comments appear to refer to the initial Implementation Plan, rather than the “Implementation Plan for Newly Identified
Automatic Reclosing Components due to generation changes in the Balancing Authority Area”.
1. The premise presented in your comment is incorrect. The Implementation Plan establishes expectations for performance of the
initial maintenance under the standard. After the initial performance of the maintenance, the entity is expected to perform
ongoing maintenance according to the intervals in Table 4.
2. The statement to which you refer is intended to clarify that auditors should not expect evidence of multiple performances of the
maintenance until two full intervals have transpired. The majority of industry agrees with the phased‐in approach for
Consideration of Comments: Project 2007‐17.2 | August 2013
46
Organization
Yes or No
Question 2 Comment
implementing the maintenance requirements.
American Electric Power
No
AEP will reserve its comments on the proposed implementation plan until its concerns
on scope are eventually addressed.
Due to the current volume of standards development activity, AEP is not able to apply
the same level of rigor to this request for comment as we would normally. As a result,
the comments provided in this response are those we deemed the most significant,
and do not necessary reflect all the issues that AEP may, at some time, choose to
address.
Response: Thank you for your comment.
Manitoba Hydro
No
Although Manitoba Hydro will continue to maintain our “negative” vote for this
standard based on concerns from the PRC‐005‐2 version, we do offer the following
clarifying comments to the drafting team regarding PRC‐005‐3:
(1) General comment ‐ the words “Automatic Reclosing Components” are both
capitalized and de‐capitalized throughout the document. For example, within the
definition of a Protection System Maintenance Program (PSMP) the words are de‐
capitalized, but are then capitalized in PRC‐005‐3 R3. For consistency, Manitoba
Hydro suggests selecting one or the other.
(2) Definitions of Terms Used in Standard, PSMP ‐ capitalize the word “component”
for consistency with the rest of the standard.
(3) Background 4, Retirement of Existing Standards, Implementation Plan for
Requirements R1, R2 and R5, Implementation Plan for Requirements R3 and R4,
Implementation Plan for Requirements R1, R2 and R5 and Implementation Plan for
Requirements R3 and R4 ‐ replace “Board of Trustees” with “Board of Trustees’” for
consistency with other standards.
Response: Thank you for your comments.
Consideration of Comments: Project 2007‐17.2 | August 2013
47
Organization
Yes or No
Question 2 Comment
1. The drafting team cannot capitalize “automatic reclosing” in the definition of Protection System Maintenance Program (PSMP)
because PSMP is a NERC Glossary Term.
2. The drafting team cannot capitalize “components” in the definition of Protection System Maintenance Program (PSMP) because
PSMP is a NERC Glossary Term.
3. The drafting team made the suggested change.
Consumers Energy
No
Consumer’s Energy Ballot member is voting NEGATIVE on Project 2007‐17.2
Protection System Maintenance and Testing ‐ Phase 2 (Reclosing Relays) PRC‐005‐3
since the standard does not address how each entity is expected to obtain the
required information “the gross capacity of the largest BES generating unit with the
Balancing Authority Area” (in section 4.2.6.1) and know when it changes.
Response: Thank you for your comment.
The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project. The
drafting team understands the request but contends that such a requirement would be more appropriately included in a Reliability
Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC Issues Database for
consideration when the pertinent Reliability Standard is revised.
Dominion
No
Given that most of the Maximum Maintenance Intervals appear to be in the 4‐6 year
range, we believe that implementation for newly identified Automatic Reclosing
Components due to generation changes in the Balancing Authority Area should be
extended to allow up to 36 months from BA notification of such change
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Pepco Holdings Inc & Affiliates
No
In order to verify the reclosing scheme performance on any newly identified busses,
resulting from generation capacity increases, it may require scheduling sequential line
Consideration of Comments: Project 2007‐17.2 | August 2013
48
Organization
Yes or No
Question 2 Comment
outages on all BES lines emanating from the bus in order to test breaker auto‐
reclosing operations. Also, based on system operating conditions, these individual
line outages may require coordination with certain generation outages. As such, due
to the outage coordination necessary to perform this testing, it may not be possible to
complete all testing and maintenance activities on these newly identified facilities by
the end of the following calendar year. For this reason, we would suggest the
following language (similar to that used in the first bullet of R3/R4 Section 5 of the
April 2013 draft of the PRC‐005‐3 Implementation Plan) be used for the
implementation plan for these newly identified Automatic Reclosing Components:
“The responsible entities must complete the maintenance activities, described in
Table 4, for any newly identified Automatic Reclosing Components, resulting from the
addition, or retirement, of generating units; or increases of gross generation capacity
of individual generating units or plants within the Balancing Authority area, by the first
day of the first calendar quarter thirty‐six (36) months following implementation of
the capacity change, which resulted in the identification of these new Automatic
Reclosing Components (or, for generating plants with scheduled outage intervals
exceeding three years, at the conclusion of the first succeeding maintenance outage
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Occidental Chemical Corp.
(Ingleside Cogeneration LP)
No
Ingleside Cogeneration contends that the one year time‐frame given to incorporate all
the components of Automatic Reclosers newly identified as applicable to PRC‐005‐3
due to a generation change in the BA footprint is insufficient. It is appropriate to
require the PSMP to be updated with the new components by that date, but not to
conduct the first full set of maintenance activities. Our primary concern is that
Ingleside, as a Generator Owner, will not receive timely notification that a substantive
change has been made. And although we are willing to reach out to our Balancing
Consideration of Comments: Project 2007‐17.2 | August 2013
49
Organization
Yes or No
Question 2 Comment
Authority on a regular basis ‐ or to establish a notification process ‐ this is not a
coordination activity that either of us have historically pursued. Furthermore, the
recloser relays maintenance is handled during planned outages. At the very least, we
would need an additional three years to schedule and execute the Table 4
maintenance activities in a quality manner. Since a single miss to PRC‐005‐3 would
result in a big dollar penalty, we believe that there is some reasonable leeway that
should be provided. Four years beyond the date of the generation change is not
excessive ‐ particularly since the failure of reclosing relays has not been found as the
cause of a major BES event, or even a common issue in less extensive failures.
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Southern Company
No
Southern Company contends that the two implementation plans associated with the
Standard are in conflict. It can be interpreted that all automatic reclosing components
will be ‘newly identified’. As such they would be required to be completed by the end
of the following calendar year.
We believe that the intent was to have the initial applicable Automatic Reclosing
Components to have the same phased in completion dates that were brought forward
form PRC‐005‐2.If that was the intent, an potential conflict exists since after the initial
phased in schedule up to 12 yrs is set, a change in the unit applicability could occur
one year later which could in the case of ‘largest unit’ retirement bring many more
locations into scope all of which would be newly indentified and be subject to the one
calendar year requirement.
Bottom Line is that the Implementation plan needs to be revisited.
Related to the comment to #2 above, we do not specifically see a timeline identified
to include the following:1) Identification to identify the units and components
Consideration of Comments: Project 2007‐17.2 | August 2013
50
Organization
Yes or No
Question 2 Comment
covered.2) Identification of the components that may be excluded per the Note.3)
Modification to the PSMP4) Actual Implementation
If the intent is for all this to be covered in R1 and R2, we question this for the
following reasons: o Is this enough time for the initial steps noted above, and o This
result in multiple dates for compliance with R1 and R2
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Idaho Power Company
No
The change in generation could bring in significant numbers of additional units to be
added to the testing and maintenance procedures. We would prefer a percentage
based approach similar to the implementation plan for the other table items in PRC‐
005‐2.
Response: Thank you for your comment.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Xcel Energy
No
The implementation plan for the initial implementation of the program allows for a
gradual implementation of requirements R3 and R4 for reclosing relay maintenance
activities for those relays determined to be in scope such that 30% must be compliant
within 36 months of regulatory approval, 60% compliant within 60 months of
regulatory approval, and 100% compliant within 84 months of regulatory approval.
The additional implementation plan requires 100% compliance within the next
following calendar year even in those circumstances where the retirement of the
largest unit in the balancing authority would result in an entirely different set of
reclosing relays to be in scope. For consistency, it would be far more reasonable for
Consideration of Comments: Project 2007‐17.2 | August 2013
51
Organization
Yes or No
Question 2 Comment
the additional implementation plan to be aligned with the requirements of the
original implementation plan for R3 and R4. Specifically, entities should be compliant
with R1, R2, and R5 for the newly in scope schemes at the start of the first calendar
quarter 12 months following notification of a change in generation necessitating
additional reclosing relays be added to the maintenance program or change in the
largest unit in the BA area. For requirements R3 and R4, entities shall be 30%
compliant within 36 months following notification of a change in generation
necessitating additional reclosing relays be added to the maintenance program or
change in the largest unit in the BA area, 60% compliant within 60 months following
notification of a change in generation necessitating additional reclosing relays be
added to the maintenance program or change in the largest unit in the BA area and
100% compliant within 84 months following notification of a change in generation
necessitating additional reclosing relays be added to the maintenance program or
change in the largest unit in the BA area.
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
MRO NERC Standards Review
Forum (NSRF)
No
The implementation plan should be based upon the existing maintenance schedules
for the affected BES components.
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
American Transmission
Company, LLC
No
The implementation plan should be based upon the existing maintenance schedules
for the affected BES components.
Consideration of Comments: Project 2007‐17.2 | August 2013
52
Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Liberty Electric Power
No
The program as written requires 30% compliance at 60 months. This implies two
instances of 12‐year maintenance have to occur in 5 years, or 19 years earlier than
should be required. The plan should be changed to all relays must have the first
maintenance completed by 144 months from the effective date of the standard.
Response: Thank you for your comments.
The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due to
generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan to
consolidate the implementation documents.
Independent Electricity System
Operator
No
We appreciate the drafting team’s effort to insert appropriate wording to remove a
potential conflict with Ontario regulatory practice with respect to the effective date of
the standard. However, there are still a couple of places where this insertion is
missing. Please insert: “, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.” prior to the wording “,or in those
jurisdiction....” in Section 4 on P.2 and in the first paragraph under the Retirement of
Existing Standards” on P.3.
Response: Thank you for your comments.
The drafting team modified the Implementation Plan to incorporate the intent of your suggestion.
Cleco
No
We do not believe reclosing relays are protective devices and therefore are not
subject to this level of oversight. Second, the strongest justification was that if the
relay failed to operate correctly and reclosed instantaneously, the generator would be
Consideration of Comments: Project 2007‐17.2 | August 2013
53
Organization
Yes or No
Question 2 Comment
subject to additional fault duty. We have not seen such a failure and do not see the
justification for including reclosing relays or restoration devices in a Protection System
Maintenance & Testing Standard. Major storm events near the station or breakers
failing to latch are far more likely to cause sequential faults.
Response: Thank you for your comments.
FERC Order 758 directed that maintenance of reclosing relays that affect the reliable operation of the Bulk Power System be
addressed. PRC‐005‐3 addresses this directive, and follows the recommendations included in the SAMS/SPCS technical document
“Considerations for Maintenance and Testing of Autoreclosing Schemes.”
Duke Energy
Yes
1. Duke Energy requests clarification from the drafting team as to whom they
envision identifying the newly acquired Automatic Reclosing Components, how
they must identify, and what documentation is needed to show
correspondence with an entity’s maintenance program.
2. Also, Duke Energy suggests that the drafting team consider placing the
Implementation Plan for Newly identified Automatic Reclosing Components in
the standard itself, and not as its own document.
Response: Thank you for your comments.
1. The applicable entity is expected to communicate with its BA(s) to identify applicable Automatic Reclosing components (in
accordance with the Applicability). How the correspondence is documented is left to the discretion of the entity.
2. The drafting team added additional time to the “Implementation Plan for Newly identified Automatic Reclosing Components due
to generation changes in the Balancing Authority Area.” The document was also incorporated into the full Implementation Plan
to consolidate the implementation documents.
Northeast Power Coordinating
Council
Yes
1. Referencing Applicability Section 4.2.6, the Balancing Authority has to notify
and provide documentation to the appropriate entities in 4.2.6.1 and 4.2.6.2
that automatic reclosing maintenance is required. TO substations within 10
circuit miles will need to be identified by the Balancing Authority as well.
2. To clarify Footnote 1 on page 4, suggest the following rewording:Automatic
Consideration of Comments: Project 2007‐17.2 | August 2013
54
Organization
Yes or No
Question 2 Comment
Reclosing as addressed in Sections 4.2.6.1 and 4.2.6.2 may be excluded if the
equipment owner can demonstrate that a close in three‐phase fault not
cleared for the length of a breaker trip‐close‐trip operating time does not
result in a total loss of gross generation in the Interconnection exceeding the
gross capacity of the largest BES generating unit within the Balancing Authority
Area where the Automatic Reclosing is applied.
3. In the Implementation Plan the drafting team did a good job inserting the
appropriate wording to remove a potential conflict with regulatory practice
with respect to the effective date of the standard. However, the wording
needs to be inserted in Section 4 of the Background Section. Review the
Implementation Plan and insert the following words where appropriate:”, or as
otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.” The Implementation Plan must be made available
throughout the life of the Standard.
Response: Thank you for your comments.
1. The addition of a functional entity to the Applicability section of the standard is outside the scope of the SAR for this project.
The drafting team understands the request but contends that such a requirement would be more appropriately included in a
Reliability Standard applicable to Balancing Authorities; consequently, the drafting team has added this issue to the NERC
Issues Database for consideration when the pertinent Reliability Standard is revised. The drafting team contends that the
Transmission Owner, Generator Owner, and Distribution Provider are responsible to identify topology issues such as those to
which you refer.
2. The drafting team contends the footnote is consistent with the recommendations from the SAMS/SPCS report.
3. The drafting team updated the Implementation Plan language.
Oklahoma Gas & Electric
Yes
SPP Standards Review Group
Yes
Western Area Power
Yes
Consideration of Comments: Project 2007‐17.2 | August 2013
55
Organization
Yes or No
Question 2 Comment
Administration
PacifiCorp
Yes
Tacoma Power
Yes
City of Tallahassee
Yes
City of Tallahassee
Yes
Texas Reliability Entity, Inc.
Yes
Oncor Electric Delivery
Company LLC
Yes
ITC
Yes
END OF REPORT
Consideration of Comments: Project 2007‐17.2 | August 2013
56
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from July 10, 2013 through
August 23, 2013.
5. Draft 2 of PRC-005-3 passed ballot with Quorum – 78.33% and Approval – 79.24%.
Description of Current Draft:
This is the second draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions
1. Conduct final ballot
Anticipated Date
October 2013
2. BOT Adoption
November 2013
Draft 2: October, 2013
1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, the following defined term will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and automatic reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 2: October, 2013
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Draft 2: October, 2013
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
Draft 2: October, 2013
4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System
shall be included in a time-based program as
Component Type – Either any one
described in Table 1-4 and Table 3.
of the five specific elements of the
Protection System definition or any
1.2. Include the applicable monitored Component
one of the two specific elements of
attributes applied to each Protection System and
the Automatic Reclosing definition.
Automatic Reclosing Component Type consistent
with the maintenance intervals specified
in Tables 1-1 through 1-5, Table 2, Table
3, and Table 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System and Automatic Reclosing
Components.
R2. Each Transmission Owner, Generator Owner,
and Distribution Provider that uses
performance-based maintenance intervals in its
PSMP shall follow the procedure established in
PRC-005 Attachment A to establish and
maintain its performance-based intervals.
[Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
Draft 2: October, 2013
Component – A component is any individual discrete
piece of equipment included in a Protection System or
in Automatic Reclosing, including but not limited to a
protective relay, reclosing relay, or current sensing
device. The designation of what constitutes a control
circuit component is very dependent upon how an
entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a
breaker basis whereas others test their circuitry on a
local zone of protection basis. Thus, entities are
allowed the latitude to designate their own definitions
of control circuit components. Another example of
where the entity has some discretion on determining
what constitutes a single component is the voltage and
current sensing devices, where the entity may choose
either to designate a full three-phase set of such
devices or a single device as a single component.
5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
R5.
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
Unresolved Maintenance Issue – A
Each Transmission Owner, Generator Owner, and
deficiency identified during a maintenance
Distribution Provider shall demonstrate efforts to
activity that causes the component to not
correct identified Unresolved Maintenance Issues.
meet the intended performance, cannot be
[Violation Risk Factor: Medium] [Time Horizon:
corrected during the maintenance interval,
Operations Planning]
and requires follow-up corrective action.
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6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Draft 2: October, 2013
7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
Draft 2: October, 2013
9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Draft 2: October, 2013
10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
Component Type in accordance with
their performance-based PSMP.
Component Type in accordance
with their performance-based
PSMP.
Component Type in accordance with
their performance-based PSMP.
Component Type in accordance
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Draft 2: October, 2013
11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
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12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to include Automatic Reclosing in
maintenance programs
Project 2007-17.2
Revision to address the
FERC directive in Order
No.758 regarding
Automatic Reclosing
3
Draft 2: October, 2013
TBD
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 2: October, 2013
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
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15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
6 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
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16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 2: October, 2013
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
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18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Draft 2: October, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
Draft 2: October, 2013
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 2: October, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Draft 2: October, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 2: October, 2013
Verify that the dc supply can perform as manufactured when ac power is
not present.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Draft 2: October, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Draft 2: October, 2013
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Unmonitored control circuitry associated with SPS.
Draft 2: October, 2013
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 2: October, 2013
No periodic
maintenance
specified
None.
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Test and, if necessary calibrate.
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 2: October, 2013
28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
Draft 2: October, 2013
29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Alarming for power supply failure (See Table 2).
Draft 2: October, 2013
12 Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
30
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
Draft 2: October, 2013
31
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
Draft 2: October, 2013
32
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of Components included in each designated Segment,
with a minimum Segment population of 60 Components.
2. Maintain the Components in each Segment according to the time-based maximum
allowable intervals established in Tables
1-1 through 1-5, Table 3, and Tables 4-1
Segment – Components of a consistent design
through 4-2 until results of maintenance
standard, or a particular model or type from a
activities for the Segment are available
single manufacturer that typically share other
common elements. Consistent performance is
for a minimum of 30 individual
expected across the entire population of a
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment
to determine the overall performance
of the Segment and develop
maintenance intervals.
Segment. A Segment must contain at least sixty
(60) individual Components.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors, software
errors, relay settings different from specified settings,
Protection System Component or Automatic
Reclosing configuration or application errors are not
included in Countable Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than
4% of the Components within the Segment, for the greater of either the last 30
Components maintained or all Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
Draft 2: October, 2013
33
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
Draft 2: October, 2013
34
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from July 10, 2013 through
August 23, 2013.
5. Draft 2 of PRC-005-3 passed ballot with Quorum – 78.33% and Approval – 79.24%.
Description of Current Draft:
This is the second draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions
1. Post for a concurrent 45-day comment and ballot
July 2013
2.1. Conduct recirculationfinal ballot
October 2013
3.2. BOT Adoption
November 2013
Draft 2: JulyOctober, 2013
Anticipated Date
1
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, the following defined term will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and automatic reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 2: JulyOctober, 2013
2
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Draft 2: JulyOctober, 2013
3
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-3
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that they are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
Draft 2: JulyOctober, 2013
4
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall establish a
Protection System Maintenance Program (PSMP) for its Protection Systems and Automatic
Reclosing identified in Facilities Section 4.2. [Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
The PSMP shall:
1.1. Identify which maintenance method (time-based, performance-based per PRC-005
Attachment A, or a combination) is used to address each Protection System and
Automatic Reclosing Component Type. All batteries associated with the station dc
supply Component Type of a Protection System
shall be included in a time-based program as
Component Type – Either any one
described in Table 1-4 and Table 3.
of the five specific elements of the
Protection System definition or any
1.2. Include the applicable monitored Component
one of the two specific elements of
attributes applied to each Protection System and
the Automatic Reclosing definition.
Automatic Reclosing Component Type consistent
with the maintenance intervals specified
in Tables 1-1 through 1-5, Table 2, Table
3, and Table 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System and Automatic Reclosing
Components.
R2. Each Transmission Owner, Generator Owner,
and Distribution Provider that uses
performance-based maintenance intervals in its
PSMP shall follow the procedure established in
PRC-005 Attachment A to establish and
maintain its performance-based intervals.
[Violation Risk Factor: Medium] [Time
Horizon: Operations Planning]
Draft 2: JulyOctober, 2013
Component – A component is any individual discrete
piece of equipment included in a Protection System or
in Automatic Reclosing, including but not limited to a
protective relay, reclosing relay, or current sensing
device. The designation of what constitutes a control
circuit component is very dependent upon how an
entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a
breaker basis whereas others test their circuitry on a
local zone of protection basis. Thus, entities are
allowed the latitude to designate their own definitions
of control circuit components. Another example of
where the entity has some discretion on determining
what constitutes a single component is the voltage and
current sensing devices, where the entity may choose
either to designate a full three-phase set of such
devices or a single device as a single component.
5
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 4-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
R5. Each Transmission Owner, Generator Owner, and
Distribution Provider shall demonstrate efforts to
correct identified Unresolved Maintenance Issues.
[Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
Draft 2: JulyOctober, 2013
Unresolved Maintenance Issue – A
deficiency identified during a maintenance
activity that causes the component to not
meet the intended performance, cannot be
corrected during the maintenance interval,
and requires follow-up corrective action.
6
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each Protection System and Automatic Reclosing Component
Type (such as manufacturer’s specifications or engineering drawings) of the appropriate
monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2, Table 3, and
Table 4-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Self-Certification
Draft 2: JulyOctober, 2013
7
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Draft 2: JulyOctober, 2013
8
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Component Type consistent with the
maintenance intervals specified in
Tables 1-1 through 1-5, Table 2,
Table 3, and Tables 4-1 through 4-2
where monitoring is used to extend
the maintenance intervals beyond
those specified for unmonitored
Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entity’s PSMP
failed to specify whether four or
more Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
Draft 2: JulyOctober, 2013
9
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the Segment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Components included within a
time-based maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific
Component Type, in accordance with
the minimum maintenance activities
and maximum maintenance intervals
prescribed within Tables 1-1 through
1-5, Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 5% but 10% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, Table 3, and Tables 4-1
through 4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 10% but 15% or
less of the total Components
included within a specific
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, Table 3, and Tables 4-1 through
4-2.
For Components included within a
time-based maintenance program,
the responsible entity failed to
maintain more than 15% of the total
Components included within a
specific Component Type, in
accordance with the minimum
maintenance activities and
maximum maintenance intervals
prescribed within Tables 1-1
through 1-5, Table 2, Table 3, and
Tables 4-1 through 4-2.
R4
For Components included within a
performance-based maintenance
program, the responsible entity failed
to maintain 5% or less of the annual
scheduled maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 5% but
10% or less of the annual scheduled
maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 10%
but 15% or less of the annual
scheduled maintenance for a specific
For Components included within a
performance-based maintenance
program, the responsible entity
failed to maintain more than 15%
of the annual scheduled
maintenance for a specific
Draft 2: JulyOctober, 2013
10
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
Component Type in accordance with
their performance-based PSMP.
Component Type in accordance
with their performance-based
PSMP.
Component Type in accordance with
their performance-based PSMP.
Component Type in accordance
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
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11
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
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12
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to include Automatic Reclosing in
maintenance programs
Project 2007-17.2
Revision to address the
FERC directive in Order
No.758 regarding
Automatic Reclosing
3
Draft 2: JulyOctober, 2013
TBD
13
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
Draft 2: JulyOctober, 2013
14
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
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15
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 Calendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a category
below.
6 Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
12 Calendar
Years
Verify that the communications system meets performance
criteria pertinent to the communications technology applied (e.g.
signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 Calendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
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16
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
Draft 2: JulyOctober, 2013
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
17
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
Draft 2: JulyOctober, 2013
18
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
Draft 2: JulyOctober, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
19
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Inspect:
6 Calendar Months
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
Draft 2: JulyOctober, 2013
20
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
Draft 2: JulyOctober, 2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
21
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
Draft 2: JulyOctober, 2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
22
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
Draft 2: JulyOctober, 2013
Verify that the dc supply can perform as manufactured when ac power is
not present.
23
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
Draft 2: JulyOctober, 2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
24
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Draft 2: JulyOctober, 2013
25
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
12 Calendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
12 Calendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
Control circuitry associated with protective functions and/or SPSs whose
integrity is monitored and alarmed (See Table 2).
No periodic
maintenance
specified
None.
Unmonitored control circuitry associated with SPS.
Draft 2: JulyOctober, 2013
26
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5, Table 3, and
Tables 4-1 through 4-2 are conveyed from the alarm origin to the location where
corrective action can be initiated, and not having all the attributes of the “Alarm
Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
Draft 2: JulyOctober, 2013
No periodic
maintenance
specified
None.
27
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Test and, if necessary calibrate.
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Verify:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Settings are as specified.
12 Calendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
Draft 2: JulyOctober, 2013
28
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 Calendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 Calendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 Calendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
Draft 2: JulyOctober, 2013
29
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Alarming for power supply failure (See Table 2).
Draft 2: JulyOctober, 2013
12 Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
30
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
Draft 2: JulyOctober, 2013
31
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
Draft 2: JulyOctober, 2013
32
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of Components included in each designated Segment,
with a minimum Segment population of 60 Components.
2. Maintain the Components in each Segment according to the time-based maximum
allowable intervals established in Tables
1-1 through 1-5, Table 3, and Tables 4-1
Segment – Components of a consistent design
through 4-2 until results of maintenance
standard, or a particular model or type from a
activities for the Segment are available
single manufacturer that typically share other
common elements. Consistent performance is
for a minimum of 30 individual
expected across the entire population of a
Components of the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and
Countable Events for each included
Component.
4. Analyze the maintenance program
activities and results for each Segment
to determine the overall performance
of the Segment and develop
maintenance intervals.
Segment. A Segment must contain at least sixty
(60) individual Components.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors, software
errors, relay settings different from specified settings,
Protection System Component or Automatic
Reclosing configuration or application errors are not
included in Countable Events.
5. Determine the maximum allowable
maintenance interval for each Segment
such that the Segment experiences
Countable Events on no more than
4% of the Components within the Segment, for the greater of either the last 30
Components maintained or all Components maintained in the previous year.
To maintain the technical justification for the ongoing use of a performance-based PSMP:
1. At least annually, update the list of Components and Segments and/or description if any
changes occur within the Segment.
2. Perform maintenance on the greater of 5% of the Components (addressed in the
performance based PSMP) in each Segment or 3 individual Components within the
Segment in each year.
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
Draft 2: JulyOctober, 2013
33
Standard PRC-005-3 — Protection System and Automatic Reclosing Maintenance
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Segment maintained through a performance-based PSMP
experience 4% or more Countable Events, develop, document, and implement an action
plan to reduce the Countable Events to less than 4% of the Segment population within 3
years.
Draft 2: JulyOctober, 2013
34
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. Standards Committee approved posting SAR and draft standard on January 17, 2013.
2. SAR posted for 30-day informal comment period from April 5, 2013 through May 6, 2013.
3. Draft 1 of PRC-005-3 posted for a 30-day formal comment period from April 5, 2013 through
May 6, 2013.
4. Draft 2 of PRC-005-3 posted for a 45-day formal comment period from July 10, 2013 through
August 23, 2013.
5. Draft 2 of PRC-005-3 passed ballot with Quorum – 78.33% and Approval – 79.24%.
Description of Current Draft:
This is the second draft of the PRC-005-3. The standard modifies PRC-005-2 to address the directive
issued by the Federal Energy Regulatory Commission in Order No.758 for “NERC to include the
maintenance and testing of reclosing relays that can affect the reliable operation of the Bulk-Power
System...”
Future Development Plan:
Anticipated Actions
1. Conduct final ballot
Anticipated Date
October 2013
2. BOT Adoption
November 2013
Draft 2: October, 2013
1
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, the following defined term will be removed from the individual standard and added to the
Glossary.
Protection System Maintenance Program (PSMP) (NERC Board of Trustees Approved
Definition) — An ongoing program by which Protection System and automatic reclosing components
are kept in working order and proper operation of malfunctioning components is restored. A maintenance
program for a specific component includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in-service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Examine for signs of component failure, reduced performance or degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
The following terms are defined for use only within PRC-005-3, and should remain with the standard
upon approval rather than being moved to the Glossary of Terms.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay.
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that causes the
component to not meet the intended performance, cannot be corrected during the maintenance interval,
and requires follow-up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a single
manufacturer that typically share other common elements. Consistent performance is expected across the
entire population of a Segment. A Segment must contain at least sixty (60) individual Components.
Component Type – Either any one of the five specific elements of the Protection System definition or
any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a Protection
System or in Automatic Reclosing, including but not limited to a protective relay, reclosing relay, or
current sensing device. The designation of what constitutes a control circuit Component is dependent
upon how an entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of control circuit Components. Another
example of where the entity has some discretion on determining what constitutes a single Component is
the voltage and current sensing devices, where the entity may choose either to designate a full three-phase
set of such devices or a single device as a single Component.
Draft 2: October, 2013
2
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Countable Event – A failure of a Component requiring repair or replacement, any condition discovered
during the maintenance activities in Tables 1-1 through 1-5, Table 3, and Tables 4-1 through 4-2 which
requires corrective action or a Protection System Misoperation attributed to hardware failure or
calibration failure. Misoperations due to product design errors, software errors, relay settings different
from specified settings, Protection System Component or Automatic Reclosing configuration or
application errors are not included in Countable Events.
Draft 2: October, 2013
3
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
A. Introduction
1.
Title:
Protection System and Automatic Reclosing Maintenance
2.
Number:
PRC-005-23
3.
Purpose:
To document and implement programs for the maintenance of all Protection
Systems and Automatic Reclosing affecting the reliability of the Bulk Electric System (BES)
so that these Protection Systemsthey are kept in working order.
4.
Applicability:
4.1. Functional Entities:
4.1.1
Transmission Owner
4.1.2
Generator Owner
4.1.3
Distribution Provider
4.2. Facilities:
4.2.1
Protection Systems that are installed for the purpose of detecting Faults on BES
Elements (lines, buses, transformers, etc.)
4.2.2
Protection Systems used for underfrequency load-shedding systems installed per
ERO underfrequency load-shedding requirements.
4.2.3
Protection Systems used for undervoltage load-shedding systems installed to
prevent system voltage collapse or voltage instability for BES reliability.
4.2.4
Protection Systems installed as a Special Protection System (SPS) for BES
reliability.
4.2.5
Protection Systems for generator Facilities that are part of the BES, including:
4.2.5.1 Protection Systems that act to trip the generator either directly or via lockout
or auxiliary tripping relays.
4.2.5.2 Protection Systems for generator step-up transformers for generators that are
part of the BES.
4.2.5.3 Protection Systems for transformers connecting aggregated generation,
where the aggregated generation is part of the BES (e.g., transformers
connecting facilities such as wind-farms to the BES).
4.2.5.4 Protection Systems for station service or excitation transformers connected to
the generator bus of generators which are part of the BES, that act to trip the
generator either directly or via lockout or tripping auxiliary relays.
4.2.6
Automatic Reclosing1, including:
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the
BES bus located at generating plant substations where the total installed
1
Automatic Reclosing addressed in Section 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can
demonstrate that a close-in three-phase fault present for twice the normal clearing time (capturing a minimum tripclose-trip time delay) does not result in a total loss of gross generation in the Interconnection exceeding the gross
capacity of the largest BES generating unit within the Balancing Authority Area where the Automatic Reclosing is
applied.
Draft 2: October, 2013
4
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
gross generating plant capacity is greater than the gross capacity of the
largest BES generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at
substations one bus away from generating plants specified in Section 4.2.6.1
when the substation is less than 10 circuit-miles from the generating plant
substation.
4.2.6.3 Automatic Reclosing applied as an integral part of an SPS specified in
Section 4.2.4.
5.
Effective Date: See Implementation Plan
B. Requirements
R1. Each Transmission Owner, Generator Owner, and
Distribution Provider shall establish a Protection System
Maintenance Program (PSMP) for its Protection Systems
and Automatic Reclosing identified in Facilities Section 4.2.
[Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
Component Type - Any one of
the five specific elements of the
Protection System definition.
Component Type – Either any one
of the five specific elements of the
Protection System definition or any
one of the two specific elements of
the Automatic Reclosing definition.
Component – A component is any individual discrete piece of
equipment included in a Protection System, including but not limited
to a protective relay or current sensing device. The designation of
what constitutes a control circuit component is very dependent upon
how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis
whereas others test their circuitry on a local zone of protection
basis. Thus, entities are allowed the latitude to designate their own
definitions of control circuit components. Another example of where
the entity has some discretion on determining what constitutes a
single component is the voltage and current sensing devices, where
the entity may choose either to designate a full three-phase set of
such devices or a single device as a single component.
The PSMP shall:
1.1. Identify which maintenance
method (time-based,
performance-based per PRC005 Attachment A, or a
combination) is used to
address each Protection
System and Automatic
Reclosing Component Type.
All batteries associated with
the station dc supply
Component Type of a
Protection System shall be
included in a time-based
program as described in
Table 1-4 and Table 3.
Component – A component is any individual discrete piece of
equipment included in a Protection System or in Automatic
Reclosing, including but not limited to a protective relay, reclosing
relay, or current sensing device. The designation of what
constitutes a control circuit component is very dependent upon how
an entity performs and tracks the testing of the control circuitry.
Some entities test their control circuits on a breaker basis whereas
others test their circuitry on a local zone of protection basis. Thus,
entities are allowed the latitude to designate their own definitions of
control circuit components. Another example of where the entity
has some discretion on determining what constitutes a single
component is the voltage and current sensing devices, where the
entity may choose either to designate a full three-phase set of such
devices or a single device as a single component.
1.2. Include the applicable
monitored Component
attributes applied to each
Protection System and
Automatic Reclosing
Component Type consistent
with the maintenance
intervals specified in Tables
1-1 through 1-5, Table 2,
Draft 2: October, 2013
5
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Table 3, and Table 34-1 through 4-2 where monitoring is used to extend the maintenance
intervals beyond those specified for unmonitored Protection System and Automatic
Reclosing Components.
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals in its PSMP shall follow the procedure established in PRC-005
Attachment A to establish and maintain its performance-based intervals. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning]
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall maintain its Protection System and Automatic Reclosing
Components that are included within the time-based maintenance program in accordance with
the minimum maintenance activities and maximum maintenance intervals prescribed within
Tables 1-1 through 1-5, Table 2, Table 3, and Table 34-1 through 4-2. [Violation Risk Factor:
High] [Time Horizon: Operations Planning]
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
R5.
performance-based maintenance program(s) in accordance with Requirement R2 shall
implement and follow its PSMP for its Protection System and Automatic Reclosing
Components that are included within the performance-based program(s). [Violation Risk
Factor: High] [Time Horizon: Operations Planning]
Unresolved Maintenance Issue – A
Each Transmission Owner, Generator Owner, and
deficiency identified during a maintenance
Distribution Provider shall demonstrate efforts to
activity that causes the component to not
correct identified Unresolved Maintenance Issues.
meet the intended performance, cannot be
[Violation Risk Factor: Medium] [Time Horizon:
corrected during the maintenance interval,
Operations Planning]
and requires follow-up corrective action.
Draft 2: October, 2013
6
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
C. Measures
M1. Each Transmission Owner, Generator Owner and Distribution Provider shall have a
documented Protection System Maintenance Program in accordance with Requirement R1.
For each Protection System and Automatic Reclosing Component Type, the documentation
shall include the type of maintenance method applied (time-based, performance-based, or a
combination of these maintenance methods), and shall include all batteries associated with the
station dc supply Component Types in a time-based program as described in Table 1-4 and
Table 3. (Part 1.1)
For Component Types that use monitoring to extend the maintenance intervals, the responsible
entity(s) shall have evidence for each protectionProtection System and Automatic Reclosing
Component Type (such as manufacturer’s specifications or engineering drawings) of the
appropriate monitored Component attributes as specified in Tables 1-1 through 1-5, Table 2,
Table 3, and Table 34-1 through 4-2. (Part 1.2)
M2. Each Transmission Owner, Generator Owner, and Distribution Provider that uses performancebased maintenance intervals shall have evidence that its current performance-based
maintenance program(s) is in accordance with Requirement R2, which may include but is not
limited to Component lists, dated maintenance records, and dated analysis records and results.
M3. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes timebased maintenance program(s) shall have evidence that it has maintained its Protection System
and Automatic Reclosing Components included within its time-based program in accordance
with Requirement R3. The evidence may include but is not limited to dated maintenance
records, dated maintenance summaries, dated check-off lists, dated inspection records, or dated
work orders.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider that utilizes
performance-based maintenance intervals in accordance with Requirement R2 shall have
evidence that it has implemented the Protection System Maintenance Program for the
Protection System and Automatic Reclosing Components included in its performance-based
program in accordance with Requirement R4. The evidence may include but is not limited to
dated maintenance records, dated maintenance summaries, dated check-off lists, dated
inspection records, or dated work orders.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence
that it has undertaken efforts to correct identified Unresolved Maintenance Issues in
accordance with Requirement R5. The evidence may include but is not limited to work orders,
replacement Component orders, invoices, project schedules with completed milestones, return
material authorizations (RMAs) or purchase orders.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
means NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Compliance Monitoring and Enforcement Processes:
Compliance Audit
Draft 2: October, 2013
7
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Evidence Retention
The following evidence retention periods identify the period of time an entity is required
to retain specific evidence to demonstrate compliance. For instances where the evidence
retention period specified below is shorter than the time since the last audit, the
Compliance Enforcement Authority may ask an entity to provide other evidence to show
that it was compliant for the full time period since the last audit.
The Transmission Owner, Generator Owner, and Distribution Provider shall each keep
data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of time
as part of an investigation.
For Requirement R1, the Transmission Owner, Generator Owner, and Distribution
Provider shall each keep its current dated Protection System Maintenance Program, as
well as any superseded versions since the preceding compliance audit, including the
documentation that specifies the type of maintenance program applied for each Protection
System Component Type.
For Requirement R2, Requirement R3, Requirement R4, and Requirement R5, the
Transmission Owner, Generator Owner, and Distribution Provider shall each keep
documentation of the two most recent performances of each distinct maintenance activity
for the Protection System or Automatic Reclosing Component, or all performances of
each distinct maintenance activity for the Protection System or Automatic Reclosing
Component since the previous scheduled audit date, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Draft 2: October, 2013
8
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
2.
Violation Severity Levels
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The responsible entity’s PSMP failed
to specify whether one Component
Type is being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1)
OR
The responsible entity’s PSMP failed
to include applicable station batteries
in a time-based program. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether two
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1)
The responsible entity’s PSMP
failed to specify whether three
Component Types are being
addressed by time-based or
performance-based maintenance, or
a combination of both. (Part 1.1).
OR
The responsible entity’s PSMP
failed to include the applicable
monitoring attributes applied to each
Protection System Component Type
consistent with the maintenance
intervals specified in Tables 1-1
through 1-5, Table 2, and Table 3,
and Tables 4-1 through 4-2 where
monitoring is used to extend the
maintenance intervals beyond those
specified for unmonitored Protection
System Components. (Part 1.2).
The responsible entity failed to
establish a PSMP.
OR
The responsible entityentity’s
PSMP failed to specify whether
threefour or more Component
Types are being addressed by timebased or performance-based
maintenance, or a combination of
both. (Part 1.1).
R2
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within three years.
NA
The responsible entity uses
performance-based maintenance
intervals in its PSMP but failed to
reduce Countable Events to no more
than 4% within four years.
The responsible entity uses
performance-based maintenance
intervals in its PSMP but:
1) Failed to establish the technical
justification described within
Requirement R2 for the initial
use of the performance-based
PSMP
OR
2) Failed to reduce Countable
Events to no more than 4%
within five years
OR
2013
Draft 2: October,
9
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
Lower VSL
Moderate VSL
High VSL
Severe VSL
3) Maintained a Segment with
less than 60 Components
OR
4) Failed to:
• Annually update the list of
Components,
OR
• Annually perform
maintenance on the greater
of 5% of the
segmentSegment
population or 3
Components,
OR
• Annually analyze the
program activities and
results for each Segment.
R3
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
5% or less of the total Components
included within a specific Protection
System Component Type, in
accordance with the minimum
maintenance activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3, and Tables 4-1
through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 5% but 10% or less of the
total Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3, and Tables 41 through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 10% but 15% or less of
the total Components included
within a specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5, Table
2, and Table 3, and Tables 4-1
through 4-2.
For Protection System Components
included within a time-based
maintenance program, the
responsible entity failed to maintain
more than 15% of the total
Components included within a
specific Protection System
Component Type, in accordance
with the minimum maintenance
activities and maximum
maintenance intervals prescribed
within Tables 1-1 through 1-5,
Table 2, and Table 3, and Tables 41 through 4-2.
R4
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performance-based
maintenance program, the
responsible entity failed to maintain
For Protection System Components
included within a performancebased maintenance program, the
responsible entity failed to maintain
Draft 2: October,
10
2013
Standard PRC-005-23 — Protection System and Automatic Reclosing Maintenance
Requirement
Number
R5
2013
Lower VSL
Moderate VSL
High VSL
Severe VSL
5% or less of the annual scheduled
maintenance for a specific Protection
System Component Type in
accordance with their performancebased PSMP.
more than 5% but 10% or less of the
annual scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
more than 10% but 15% or less of
the annual scheduled maintenance
for a specific Protection System
Component Type in accordance with
their performance-based PSMP.
more than 15% of the annual
scheduled maintenance for a
specific Protection System
Component Type in accordance
with their performance-based
PSMP.
The responsible entity failed to
undertake efforts to correct 5 or
fewer identified Unresolved
Maintenance Issues.
The responsible entity failed to
undertake efforts to correct greater
than 5, but less than or equal to 10
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 10, but less than or equal to 15
identified Unresolved Maintenance
Issues.
The responsible entity failed to
undertake efforts to correct greater
than 15 identified Unresolved
Maintenance Issues.
Draft 2: October,
11
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
E. Regional Variances
None
F. Supplemental Reference Document
The following documents present a detailed discussion about determination of maintenance intervals
and other useful information regarding establishment of a maintenance program.
1. PRC-005-2 Protection System Maintenance Supplementary Reference and FAQ — July
2012March 2013.
2. Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
December 1,
2005
1. Changed incorrect use of certain
hyphens (-) to “en dash” (–) and “em
dash (—).”
2. Added “periods” to items where
appropriate.
3. Changed “Timeframe” to “Time Frame”
in item D, 1.2.
01/20/05
1a
February 17,
2011
Added Appendix 1 - Interpretation
regarding applicability of standard to
protection of radially connected
transformers
Project 2009-17
interpretation
1a
February 17,
2011
Adopted by Board of Trustees
1a
September 26,
2011
FERC Order issued approving interpretation
of R1 and R2 (FERC’s Order is effective as
of September 26, 2011)
1.1a
February 1,
2012
Errata change: Clarified inclusion of
generator interconnection Facility in
Generator Owner’s responsibility
Revision under Project
2010-07
1b
February 3,
2012
FERC Order issued approving interpretation
of R1, R1.1, and R1.2 (FERC’s Order dated
March 14, 2012). Updated version from 1a
to 1b.
Project 2009-10
Interpretation
April 23, 2012
Updated standard version to 1.1b to reflect
FERC approval of PRC-005-1b.
Revision under Project
2010-07
1.1b
October, 2013
Draft 2:
12
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
1.1b
May 9, 2012
PRC-005-1.1b was adopted by the Board of
Trustees as part of Project 2010-07
(GOTO).
2
November 7,
2012
Adopted by Board of Trustees
Project 2007-17 Complete revision,
absorbing maintenance
requirements from PRC005-1.1b, PRC-008-0,
PRC-011-0, PRC-017-0
Revised to include Automatic Reclosing in
maintenance programs
Project 2007-17.2
Revision to address the
FERC directive in Order
No.758 regarding
Automatic Reclosing
3
October, 2013
TBD
Draft 2:
13
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
For all unmonitored relays:
Verify that settings are as specified
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes
of a category below.
6 calendar
years Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System.
Verify acceptable measurement of power system input values.
Verify:
Monitored microprocessor protective relay with the following:
Internal self-diagnosis and alarming (see Table 2).
Voltage and/or current waveform sampling three or more times per
power cycle, and conversion of samples to numeric values for
measurement calculations by microprocessor electronics.
Alarming for power supply failure (see Table 2).
Settings are as specified.
12 calendar
yearsCalendar
Years
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values.
2
For the tables in this standard, a calendar year starts on the first day of a new year (January 1) after a maintenance activity has been completed.
For the tables in this standard, a calendar month starts on the first day of the first month after a maintenance activity has been completed.
2013
Draft 2: October,
14
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-1
Component Type - Protective Relay
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval2
Maintenance Activities
Monitored microprocessor protective relay with preceding row attributes
and the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored
by a process that continuously demonstrates ability to perform as
designed, with alarming for failure (See Table 2).
12 calendar
years Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
2013
Draft 2: October,
15
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-2
Component Type - Communications Systems
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Maximum
Maintenance
Interval
4 calendar
monthsCalendar
Months
Any unmonitored communications system necessary for correct operation of
protective functions, and not having all the monitoring attributes of a
category below.
Any communications system with continuous monitoring or periodic
automated testing for the presence of the channel function, and alarming for
loss of function (See Table 2).
6 calendar years
Calendar Years
12 calendar
years Calendar
Years
Maintenance Activities
Verify that the communications system is functional.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection
System.
Verify that the communications system meets performance
criteria pertinent to the communications technology applied
(e.g. signal level, reflected power, or data error rate).
Verify operation of communications system inputs and outputs
that are essential to proper functioning of the Protection
System.
Any communications system with all of the following:
Continuous monitoring or periodic automated testing for the performance
of the channel using criteria pertinent to the communications technology
applied (e.g. signal level, reflected power, or data error rate, and alarming
for excessive performance degradation). (See Table 2)
12 calendar
yearsCalendar
Years
Verify only the unmonitored communications system inputs and
outputs that are essential to proper functioning of the Protection
System
Some or all binary or status inputs and control outputs are monitored by
a process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
2013
Draft 2: October,
16
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-3
Component Type - Voltage and Current Sensing Devices Providing Inputs to Protective Relays
Excluding distributed UFLS and distributed UVLS (see Table 3)
Component Attributes
Any voltage and current sensing devices not having monitoring
attributes of the category below.
Voltage and Current Sensing devices connected to microprocessor
relays with AC measurements are continuously verified by comparison
of sensing input value, as measured by the microprocessor relay, to an
independent ac measurement source, with alarming for unacceptable
error or failure (see Table 2).
2013
Maximum
Maintenance
Interval
Maintenance Activities
12 calendar years
Calendar Years
Verify that current and voltage signal values are provided to the
protective relays.
No periodic
maintenance
specified
None.
Draft 2: October,
17
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply using Vented Lead-Acid
(VLA) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
Battery terminal connection resistance
18 Calendar
Months
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells where cells are visible –
or measure battery cell/unit internal ohmic values where the cells are
not visible
Physical condition of battery rack
2013
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18
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(a)
Component Type – Protection System Station dc Supply Using Vented Lead-Acid (VLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
18 Calendar
Months
-or6 Calendar Years
2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Draft 2: October,
19
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
6 Calendar Months
Inspect:
Condition of all individual units by measuring battery cell/unit
internal ohmic values.
Protection System Station dc supply with Valve Regulated
Lead-Acid (VRLA) batteries not having monitoring attributes
of Table 1-4(f).
Verify:
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Physical condition of battery rack
2013
Draft 2: October,
20
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(b)
Component Type – Protection System Station dc Supply Using Valve-Regulated Lead-Acid (VRLA) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS systems, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
6 Calendar Months
-or3 Calendar Years
2013
Maintenance Activities
Verify that the station battery can perform as manufactured by
evaluating cell/unit measurements indicative of battery performance
(e.g. internal ohmic values or float current) against the station battery
baseline.
-orVerify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Draft 2: October,
21
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(c)
Component Type – Protection System Station dc Supply Using Nickel-Cadmium (NiCad) Batteries
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
Station dc supply voltage
4 Calendar Months
Inspect:
Electrolyte level
For unintentional grounds
Verify:
Protection System Station dc supply Nickel-Cadmium
(NiCad) batteries not having monitoring attributes of Table 14(f).
Float voltage of battery charger
Battery continuity
18 Calendar
Months
Battery terminal connection resistance
Battery intercell or unit-to-unit connection resistance
Inspect:
Cell condition of all individual battery cells.
Physical condition of battery rack
6 Calendar Years
2013
Verify that the station battery can perform as manufactured by
conducting a performance or modified performance capacity test of the
entire battery bank.
Draft 2: October,
22
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(d)
Component Type – Protection System Station dc Supply Using Non Battery Based Energy Storage
Excluding distributed UFLS and distributed UVLS (see Table 3)
Protection System Station dc supply used only for non-BES interrupting devices for SPS, non-distributed UFLS system, or nondistributed UVLS systems is excluded (see Table 1-4(e)).
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify:
4 Calendar Months
Station dc supply voltage
Inspect:
For unintentional grounds
Any Protection System station dc supply not using a battery
and not having monitoring attributes of Table 1-4(f).
18 Calendar Months
Inspect:
Condition of non-battery based dc supply
6 Calendar Years
2013
Verify that the dc supply can perform as manufactured when ac power is
not present.
Draft 2: October,
23
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(e)
Component Type – Protection System Station dc Supply for non-BES Interrupting Devices for SPS, non-distributed UFLS, and nondistributed UVLS systems
Component Attributes
Any Protection System dc supply used for tripping only nonBES interrupting devices as part of a SPS, non-distributed
UFLS, or non-distributed UVLS system and not having
monitoring attributes of Table 1-4(f).
2013
Maximum
Maintenance
Interval
When control
circuits are verified
(See Table 1-5)
Maintenance Activities
Verify Station dc supply voltage.
Draft 2: October,
24
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-4(f)
Exclusions for Protection System Station dc Supply Monitoring Devices and Systems
Component Attributes
Maximum Maintenance
Interval
Maintenance Activities
Any station dc supply with high and low voltage monitoring
and alarming of the battery charger voltage to detect charger
overvoltage and charger failure (See Table 2).
No periodic verification of station dc supply voltage is
required.
Any battery based station dc supply with electrolyte level
monitoring and alarming in every cell (See Table 2).
No periodic inspection of the electrolyte level for each cell is
required.
Any station dc supply with unintentional dc ground monitoring
and alarming (See Table 2).
No periodic inspection of unintentional dc grounds is
required.
Any station dc supply with charger float voltage monitoring
and alarming to ensure correct float voltage is being applied on
the station dc supply (See Table 2).
No periodic verification of float voltage of battery charger is
required.
Any battery based station dc supply with monitoring and
alarming of battery string continuity (See Table 2).
No periodic maintenance
specified
No periodic verification of the battery continuity is required.
Any battery based station dc supply with monitoring and
alarming of the intercell and/or terminal connection detail
resistance of the entire battery (See Table 2).
No periodic verification of the intercell and terminal
connection resistance is required.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with internal ohmic value or float
current monitoring and alarming, and evaluating present values
relative to baseline internal ohmic values for every cell/unit
(See Table 2).
No periodic evaluation relative to baseline of battery cell/unit
measurements indicative of battery performance is required to
verify the station battery can perform as manufactured.
Any Valve Regulated Lead-Acid (VRLA) or Vented LeadAcid (VLA) station battery with monitoring and alarming of
each cell/unit internal ohmic value (See Table 2).
2013
No periodic inspection of the condition of all individual units
by measuring battery cell/unit internal ohmic values of a
station VRLA or Vented Lead-Acid (VLA) battery is
required.
Draft 2: October,
25
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
2013
Draft 2: October,
26
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 1-5
Component Type - Control Circuitry Associated With Protective Functions
Excluding distributed UFLS and distributed UVLS (see Table 3)
Note: Table requirements apply to all Control Circuitry Components of Protection Systems, and SPSs except as noted.
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Trip coils or actuators of circuit breakers, interrupting devices, or mitigating
devices (regardless of any monitoring of the control circuitry).
6 calendar
years Calendar
Years
Verify that each trip coil is able to operate the circuit
breaker, interrupting device, or mitigating device.
Electromechanical lockout devices which are directly in a trip path from the
protective relay to the interrupting device trip coil (regardless of any
monitoring of the control circuitry).
6 calendar
years Calendar
Years
Verify electrical operation of electromechanical lockout
devices.
Unmonitored control circuitry associated with SPS.
12 calendar
yearsCalendar
Years
Verify all paths of the control circuits essential for proper
operation of the SPS.
12 calendar
yearsCalendar
Years
Verify all paths of the trip circuits inclusive of all auxiliary
relays through the trip coil(s) of the circuit breakers or other
interrupting devices.
(See Table 4-2(b) for SPS which include Automatic Reclosing.)
Unmonitored control circuitry associated with protective functions inclusive of
all auxiliary relays.
Control circuitry associated with protective functions and/or SPSSPSs whose
integrity is monitored and alarmed (See Table 2).
2013
No periodic
maintenance
specified
None.
Draft 2: October,
27
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 2 – Alarming Paths and Monitoring
In Tables 1-1 through 1-5 and, Table 3, and Tables 4-1 through 4-2, alarm attributes used to justify extended maximum maintenance
intervals and/or reduced maintenance activities are subject to the following maintenance requirements
Component Attributes
Any alarm path through which alarms in Tables 1-1 through 1-5 and, Table 3,
and Tables 4-1 through 4-2 are conveyed from the alarm origin to the location
where corrective action can be initiated, and not having all the attributes of the
“Alarm Path with monitoring” category below.
Maximum
Maintenance
Interval
Maintenance Activities
12 Calendar Years
Verify that the alarm path conveys alarm signals to
a location where corrective action can be initiated.
Alarms are reported within 24 hours of detection to a location where corrective
action can be initiated.
Alarm Path with monitoring:
The location where corrective action is taken receives an alarm within 24 hours
for failure of any portion of the alarming path from the alarm origin to the
location where corrective action can be initiated.
2013
No periodic
maintenance
specified
None.
Draft 2: October,
28
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified .
For non-microprocessor relays:
Any unmonitored protective relay not having all the monitoring attributes of a
category below.
6 calendar
years Calendar
Years
Test and, if necessary calibrate .
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Protection System.
Verify acceptable measurement of power system input
values.
Monitored microprocessor protective relay with the following:
Internal self diagnosis and alarming (See Table 2).
Voltage and/or current waveform sampling three or more times per power
cycle, and conversion of samples to numeric values for measurement
calculations by microprocessor electronics.
Verify:
12 calendar
years Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Protection System.
Acceptable measurement of power system input values
Alarming for power supply failure (See Table 2).
Monitored microprocessor protective relay with preceding row attributes and
the following:
Ac measurements are continuously verified by comparison to an
independent ac measurement source, with alarming for excessive error
(See Table 2).
Some or all binary or status inputs and control outputs are monitored by a
process that continuously demonstrates ability to perform as designed,
with alarming for failure (See Table 2).
12 calendar
years Calendar
Years
Verify only the unmonitored relay inputs and outputs that are
essential to proper functioning of the Protection System.
Alarming for change of settings (See Table 2).
2013
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29
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 3
Maintenance Activities and Intervals for distributed UFLS and distributed UVLS Systems
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Voltage and/or current sensing devices associated with UFLS or UVLS
systems.
12 calendar
years Calendar
Years
Verify that current and/or voltage signal values are provided to
the protective relays.
Protection System dc supply for tripping non-BES interrupting devices used
only for a UFLS or UVLS system.
12 calendar
yearsCalendar
Years
Verify Protection System dc supply voltage.
Control circuitry between the UFLS or UVLS relays and electromechanical
lockout and/or tripping auxiliary devices (excludes non-BES interrupting
device trip coils).
12 calendar
yearsCalendar
Years
Verify the path from the relay to the lockout and/or tripping
auxiliary relay (including essential supervisory logic).
Electromechanical lockout and/or tripping auxiliary devices associated only
with UFLS or UVLS systems (excludes non-BES interrupting device trip
coils).
12 calendar
yearsCalendar
Years
Verify electrical operation of electromechanical lockout and/or
tripping auxiliary devices.
Control circuitry between the electromechanical lockout and/or tripping
auxiliary devices and the non-BES interrupting devices in UFLS or UVLS
systems, or between UFLS or UVLS relays (with no interposing
electromechanical lockout or auxiliary device) and the non-BES interrupting
devices (excludes non-BES interrupting device trip coils).
No periodic
maintenance
specified
None.
Trip coils of non-BES interrupting devices in UFLS or UVLS systems.
No periodic
maintenance
specified
None.
2013
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30
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-1
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Reclosing Relay
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Verify that settings are as specified.
For non-microprocessor relays:
Any unmonitored reclosing relay not having all the monitoring attributes of a
category below.
6 Calendar
Years
Test and, if necessary calibrate
For microprocessor relays:
Verify operation of the relay inputs and outputs that are
essential to proper functioning of the Automatic Reclosing.
Verify:
Monitored microprocessor reclosing relay with the following:
Internal self diagnosis and alarming (See Table 2).
Alarming for power supply failure (See Table 2).
2013
12 Calendar
Years
Settings are as specified.
Operation of the relay inputs and outputs that are essential to
proper functioning of the Automatic Reclosing.
Draft 2: October,
31
Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(a)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that are NOT an Integral Part of an SPS
Maximum
Maintenance
Interval
Maintenance Activities
Unmonitored Control circuitry associated with Automatic Reclosing that is
not an integral part of an SPS.
12 Calendar
Years
Verify that Automatic Reclosing, upon initiation, does not
issue a premature closing command to the close circuitry.
Control circuitry associated with Automatic Reclosing that is not part of an
SPS and is monitored and alarmed for conditions that would result in a
premature closing command. (See Table 2)
No periodic
maintenance
specified
None.
Component Attributes
2013
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Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
Table 4-2(b)
Maintenance Activities and Intervals for Automatic Reclosing Components
Component Type – Control Circuitry Associated with Reclosing Relays that ARE an Integral Part of an SPS
Component Attributes
Maximum
Maintenance
Interval
Maintenance Activities
Close coils or actuators of circuit breakers or similar devices that are used in
conjunction with Automatic Reclosing as part of an SPS (regardless of any
monitoring of the control circuitry).
6 Calendar
Years
Verify that each close coil or actuator is able to operate the
circuit breaker or mitigating device.
Unmonitored close control circuitry associated with Automatic Reclosing
used as an integral part of an SPS.
12 Calendar
Years
Verify all paths of the control circuits associated with Automatic
Reclosing that are essential for proper operation of the SPS.
Control circuitry associated with Automatic Reclosing that is an integral part
of an SPS whose integrity is monitored and alarmed. (See Table 2)
No periodic
maintenance
specified
None.
2013
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Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
PRC-005 — Attachment A
Criteria for a Performance-Based Protection System Maintenance Program
Purpose: To establish a technical basis for initial and continued use of a performance-based
Protection System Maintenance Program (PSMP).
To establish the technical justification for the initial use of a performance-based PSMP:
1. Develop a list with a description of Components included in each designated Segment of
the Protection System Component population, with a minimum Segment population of
60 Components.
2. Maintain the Components in each Segment
according to the time-based maximum
allowable intervals established in Tables 1-1
through 1-5 and, Table 3, and Tables 4-1
through 4-2 until results of maintenance
activities for the Segment are available for a
minimum of 30 individual Components of
the Segment.
3. Document the maintenance program
activities and results for each Segment,
including maintenance dates and Countable
Events for each included Component.
4. Analyze the maintenance program activities
and results for each Segment to determine
the overall performance of the Segment and
develop maintenance intervals.
5. Determine the maximum allowable
maintenance interval for each Segment such
that the Segment experiences Countable
Events on no more than 4% of the
Components within the Segment, for the
greater of either the last 30 Components
maintained or all Components maintained in
the previous year.
To maintain the technical justification for the
ongoing use of a performance-based PSMP:
1. At least annually, update the list of
Protection System Components and
Segments and/or description if any changes
occur within the Segment.
Segment – Components of a consistent design
standard, or a particular model or type from a
single manufacturer that typically share other
common elements. Consistent performance is
expected across the entire population of a
Segment. A Segment must contain at least sixty
(60) individual Components.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5 and Table 3 which requires
corrective action, or a Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System component
configuration errors, or Protection System
application errors are not included in Countable
Events.
Countable Event – A failure of a component
requiring repair or replacement, any condition
discovered during the maintenance activities in
Tables 1-1 through 1-5, Table 3, and Tables 4-1
through 4-2 which requires corrective action, or a
Protection System Misoperation attributed to
hardware failure or calibration failure.
Misoperations due to product design errors,
software errors, relay settings different from
specified settings, Protection System Component
or Automatic Reclosing configuration or
application errors are not included in Countable
Events.
2. Perform maintenance on the greater of 5%
of the Components (addressed in the performance based PSMP) in each Segment or 3
individual Components within the Segment in each year.
2013
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Standard PRC-005-2 –3 — Protection System and Automatic Reclosing Maintenance
3. For the prior year, analyze the maintenance program activities and results for each
Segment to determine the overall performance of the Segment.
4. Using the prior year’s data, determine the maximum allowable maintenance interval for
each Segment such that the Segment experiences Countable Events on no more than 4%
of the Components within the Segment, for the greater of either the last 30 Components
maintained or all Components maintained in the previous year.
5. If the Components in a Protection System Segment maintained through a performancebased PSMP experience 4% or more Countable Events, develop, document, and
implement an action plan to reduce the Countable Events to less than 4% of the Segment
population within 3 years.
2013
Draft 2: October,
35
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC-005-3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC-005-2 – Protection System Maintenance
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth below in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2, or the combined successor standard PRC-005-3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according to PRC-005-2 (or the combined
successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, PRC-017-0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC-005-3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
2
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall remain active throughout the
phased implementation period of PRC-005-3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC-005-3. Standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty-six (156) months following applicable regulatory approval of
PRC-005-2 or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty-eight (168) months
following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of the first calendar quarter, twelve (12) calendar months following applicable regulatory approval
of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees’ adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2
or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
Protection System and Automatic Reclosing Maintenance
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October, 2013
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2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
3.
4.
The entity shall be 100% compliant on the first day of the first calendar quarter thirty-six (36)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twentyfour (24) months following applicable regulatory approval of PRC-005-2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty-eight (48)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following the November 2012
NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
4
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
5
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-2 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-2 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3 or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3 or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3 or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees’ adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
6
Implementation Plan for Newly identified Automatic Reclosing Components due to generation
changes in the Balancing Authority Area:
This applies to PRC-005-3 and successor standards.
Additional applicable Automatic Reclosing Components may be identified because of the addition or
retirement of generating units; or increases of gross generation capacity of individual generating units
or plants within the Balancing Authority Area.
In such cases, the responsible entities must complete the maintenance activities, described in Table 4,
for the newly identified Automatic Reclosing Components prior to the end of the third calendar year
following the identification of those Components unless documented prior maintenance fulfilling the
requirements of Table 4 is available.
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
Protection System and Automatic Reclosing Maintenance
Implementation Plan
October, 2013
7
Implementation Plan
Protection System and Automatic Reclosing Maintenance
PRC-005-3
Standards Involved
Approval:
• PRC-005-3 – Protection System and Automatic Reclosing Maintenance
Retirements:
PRC-005-2 – Protection System Maintenance
PRC-005-1b – Transmission and Generation Protection System Maintenance and Testing
PRC-008-0 – Implementation and Documentation of Underfrequency Load Shedding Equipment
Maintenance Program
PRC-011-0 – Undervoltage Load Shedding System Maintenance and Testing
PRC-017-0 – Special Protection System Maintenance and Testing
Prerequisite Approvals:
N/A
Background:
Reliability Standard PRC-005-2 with its associated Implementation Plan was approved by the NERC
Board of Trustees in November 2012 and has been filed with the applicable regulatory authorities for
approval. The Implementation Plan for PRC-005-3 addresses both Protection Systems as outlined in
PRC-005-2 and Automatic Reclosing components. PRC-005-3 establishes minimum maintenance
activities for Automatic Reclosing Component Types and the maximum allowable maintenance intervals
for these maintenance activities. PRC-005-3 requires entities to revise the Protection System
Maintenance Program by now including Automatic Reclosing Components. The implementation plan
established under PRC-005-2 remains unchanged except for the addition of Automatic Reclosing
Components required under PRC-005-3.
The Implementation Plan reflects consideration of the following:
1.
The requirements set forth in the proposed standard, which carry-forward requirements from PRC005-2, establish minimum maintenance activities for Protection System and Automatic Reclosing
Component Types as well as the maximum allowable maintenance intervals for these maintenance
activities. The maintenance activities established may not be presently performed by some entities
and the established maximum allowable intervals may be shorter than those currently in use by
some entities.
2.
For entities not presently performing a maintenance activity or using longer intervals than the
maximum allowable intervals established in the proposed standard, it is unrealistic for those
entities to be immediately compliant with the new activities or intervals. Further, entities should
be allowed to become compliant in such a way as to facilitate a continuing maintenance program.
3.
Entities that have previously been performing maintenance within the newly specified intervals
may not have all the documentation needed to demonstrate compliance with all of the
maintenance activities specified.
4.
The Implementation Schedule set forth below in this document carries forward the implementation
schedules contained in PRC-005-2 and includes changes needed to address the addition of
Automatic Reclosing Components in PRC-005-3. According to the combined implementation plan in
this document, entities must develop their revised Protection System Maintenance Program within
twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter twenty-four
(24) months following NERC Board of Trustees adoption of PRC-005-2. This anticipates that it will
take approximately twelve (12) months to achieve regulatory approvals following the November
2012 adoption of PRC-005-2 by the NERC Board of Trustees.
5.
The Implementation Schedule set forth in this document facilitates implementation of the more
lengthy maintenance intervals within the revised Protection System Maintenance Program in
approximately equally-distributed steps over those intervals prescribed for each respective
maintenance activity in order that entities may implement this standard in a systematic method
that facilitates an effective ongoing Protection System Maintenance Program.
General Considerations:
Each Transmission Owner, Generator Owner, and Distribution Provider shall maintain documentation to
demonstrate compliance with PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 until that entity meets
the requirements of PRC-005-2, or the combined successor standard PRC-005-3, in accordance with this
implementation plan.
While entities are transitioning to the requirements of PRC-005-2, or the combined successor standard
PRC-005-3, each entity must be prepared to identify:
All of its applicable Protection System and Automatic Reclosing Components.
Whether each component has last been maintained according toPRC-005-2 (or the combined
successor standard PRC-005-3), PRC-005-1b, PRC-008-0, PRC-011-0, PRC-017-0, or a
combination thereof.
For activities being added to an entity’s program as part of PRC-005-3 implementation, evidence may be
available to show only a single performance of the activity until two maintenance intervals have
transpired following initial implementation of PRC-005-3.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
JuneOctober, 2013
2
Retirement of Existing Standards:
Standards PRC-005-1b, PRC-008-0, PRC-011-0, and PRC-017-0 shall remain active throughout the
phased implementation period of PRC-005-3 and shall be applicable to an entity’s Protection System
Component maintenance activities not yet transitioned to PRC-005-3. Standards PRC-005-1b, PRC-0080, PRC-011-0, and PRC-017-0 shall be retired at midnight of the day immediately prior to the first day of
the first calendar quarter one hundred fifty-six (156) months following applicable regulatory approval of
PRC-005-2, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, at midnight of the day
immediately prior to the first day of the first calendar quarter one hundred sixty-eight (168) months
following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2.
The existing standard PRC-005-2 shall be retired at midnight of the day immediately prior to the first
day of the first calendar quarter, twelve (12) calendar months following applicable regulatory approval
of PRC-005-3, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities; or, in those jurisdictions where no regulatory approval is required, the first day of the first
calendar quarter twelve (12) calendar months from the date of Board of Trustees’ adoption.
Implementation Plan for Definition:
Protection System Maintenance Program – Entities shall use this definition when implementing any
portions of R1, R2 R3, R4 and R5 which use this defined term.
Implementation Plan for Requirements R1, R2 and R5:
For Protection System Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2,
or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.
For Automatic Reclosing Components, entities shall be 100% compliant on the first day of the first
calendar quarter twelve (12) months following applicable regulatory approvals of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar quarter
twenty-four (24) months following NERC Board of Trustees’ adoption of PRC-005-3, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan for Requirements R3 and R4:
1.
For Protection System Component maintenance activities with maximum allowable intervals of less
than one (1) calendar year, as established in Tables 1-1 through 1-5:
The entity shall be 100% compliant on the first day of the first calendar quarter eighteen (18)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter thirty (30)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
Protection System and Automatic Reclosing Maintenance
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JuneOctober, 2013
3
2.
For Protection System Component maintenance activities with maximum allowable intervals one
(1) calendar year or more, but two (2) calendar years or less, as established in Tables 1-1 through 15:
3.
4.
The entity shall be 100% compliant on the first day of the first calendar quarter thirty-six (36)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter forty-eight (48)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of
three (3) calendar years, as established in Tables 1-1 through 1-5:
The entity shall be at least 30% compliant on the first day of the first calendar quarter twentyfour (24) months following applicable regulatory approval of PRC-005-2 (or, for generating
plants with scheduled outage intervals exceeding two years, at the conclusion of the first
succeeding maintenance outage), or in those jurisdictions where no regulatory approval is
required, on the first day of the first calendar quarter thirty-six (36) months following the
November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2, or in those jurisdictions
where no regulatory approval is required, on the first day of the first calendar quarter fortyeight (48) months following NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter forty-eight (48)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter sixty (60)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
For Protection System Component maintenance activities with maximum allowable intervals of six
(6) calendar years, as established in Tables 1-1 through 1-5 and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-2 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following the November 2012
NERC Board of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
JuneOctober, 2013
4
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
5.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
six (6) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter thirty-six
(36) months following applicable regulatory approval of PRC-005-3 (or, for generating plants
with scheduled outage intervals exceeding three years, at the conclusion of the first succeeding
maintenance outage), or in those jurisdictions where no regulatory approval is required, on the
first day of the first calendar quarter forty-eight (48) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter eighty-four (84)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter ninety-six (96)
months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
6.
For Protection System Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Tables 1-1 through 1-5, Table 2, and Table 3:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-2, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following the November 2012 NERC Board of Trustees’ adoption of PRC-005-2 or
Protection System and Automatic Reclosing Maintenance
Implementation Plan
JuneOctober, 2013
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as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-2, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following the November 2012 NERC Board
of Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-2, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following the November 2012 NERC Board of
Trustees’ adoption of PRC-005-2 or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities.
7.
For Automatic Reclosing Component maintenance activities with maximum allowable intervals of
twelve (12) calendar years, as established in Table 4:
The entity shall be at least 30% compliant on the first day of the first calendar quarter sixty (60)
months following applicable regulatory approval of PRC-005-3, or in those jurisdictions where
no regulatory approval is required, on the first day of the first calendar quarter seventy-two
(72) months following NERC Board of Trustees’ adoption of PRC-005-3 or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
The entity shall be at least 60% compliant on the first day of the first calendar quarter following
one hundred eight (108) months following applicable regulatory approval of PRC-005-3, or in
those jurisdictions where no regulatory approval is required, on the first day of the first
calendar quarter one hundred twenty (120) months following NERC Board of Trustees’
adoption of PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such
ERO governmental authorities.
The entity shall be 100% compliant on the first day of the first calendar quarter one hundred
fifty-six (156) months following applicable regulatory approval of PRC-005-3, or in those
jurisdictions where no regulatory approval is required, on the first day of the first calendar
quarter one hundred sixty-eight (168) months following NERC Board of Trustees’ adoption of
PRC-005-3 or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Protection System and Automatic Reclosing Maintenance
Implementation Plan
JuneOctober, 2013
6
Implementation Plan for Newly identified Automatic Reclosing Components due to generation
changes in the Balancing Authority Area:
This applies to PRC-005-3 and successor standards.
Additional applicable Automatic Reclosing Components may be identified because of the addition or
retirement of generating units; or increases of gross generation capacity of individual generating units
or plants within the Balancing Authority Area.
In such cases, the responsible entities must complete the maintenance activities, described in Table 4,
for the newly identified Automatic Reclosing Components prior to the end of the third calendar year
following the identification of those Components unless documented prior maintenance fulfilling the
requirements of Table 4 is available.
Applicability:
This standard applies to the following functional entities:
Transmission Owner
Generator Owner
Distribution Provider
Protection System and Automatic Reclosing Maintenance
Implementation Plan
JuneOctober, 2013
7
``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
October 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ............. 2
2.2 Protection System Definition ............................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ................................ 3
2.3.1 Frequently Asked Questions: ........................................................................................ 4
2.4.1 Frequently Asked Questions: ........................................................................................ 6
3. Protection System and Automatic Reclosing Product Generations ......................................... 13
4. Definitions ................................................................................................................................. 15
4.1 Frequently Asked Questions: ......................................................................................... 16
5. Time‐Based Maintenance (TBM) Programs .............................................................................. 18
5.1 Maintenance Practices .................................................................................................... 18
5.1.1 Frequently Asked Questions: .................................................................................. 20
5.2 Extending Time-Based Maintenance ......................................................................... 21
5.2.1 Frequently Asked Questions: .................................................................................. 22
6. Condition‐Based Maintenance (CBM) Programs ...................................................................... 23
6.1 Frequently Asked Questions: .............................................................................................. 23
7. Time‐Based Versus Condition‐Based Maintenance .................................................................. 25
7.1 Frequently Asked Questions: ......................................................................................... 25
8. Maximum Allowable Verification Intervals............................................................................... 31
8.1 Maintenance Tests ........................................................................................................... 31
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 31
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PRC‐005‐3 Supplementary Reference and FAQ – October 2013
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4 ................. 33
8.1.3 Frequently Asked Questions: .................................................................................. 34
8.2 Retention of Records ....................................................................................................... 39
8.2.1 Frequently Asked Questions: .................................................................................. 39
8.3 Basis for Table 1 Intervals .............................................................................................. 41
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .................... 42
9. Performance‐Based Maintenance Process ............................................................................... 45
9.1 Minimum Sample Size ..................................................................................................... 46
9.2 Frequently Asked Questions: ......................................................................................... 49
10. Overlapping the Verification of Sections of the Protection System ....................................... 61
10.1 Frequently Asked Questions: ....................................................................................... 61
11. Monitoring by Analysis of Fault Records ................................................................................ 62
11.1 Frequently Asked Questions: ....................................................................................... 63
12. Importance of Relay Settings in Maintenance Programs ....................................................... 64
12.1 Frequently Asked Questions: ....................................................................................... 64
13. Self‐Monitoring Capabilities and Limitations.......................................................................... 67
13.1 Frequently Asked Questions: ....................................................................................... 68
14. Notification of Protection System or Automatic Reclosing Failures ....................................... 69
15. Maintenance Activities ........................................................................................................... 70
15.1 Protective Relays (Table 1-1) ...................................................................................... 70
15.1.1 Frequently Asked Questions: ................................................................................ 70
15.2 Voltage & Current Sensing Devices (Table 1-3) ................................................... 70
15.2.1 Frequently Asked Questions: ................................................................................ 72
15.3 Control circuitry associated with protective functions (Table 1-5) .................... 73
15.3.1 Frequently Asked Questions: ................................................................................ 75
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PRC‐005‐3 Supplementary Reference and FAQ – October 2013
15.4 Batteries and DC Supplies (Table 1-4) ................................................................... 77
15.4.1 Frequently Asked Questions: ................................................................................ 77
15.5 Associated communications equipment (Table 1-2) ................................................ 92
15.5.1 Frequently Asked Questions: ................................................................................ 93
15.6 Alarms (Table 2) ............................................................................................................ 96
15.6.1 Frequently Asked Questions: ................................................................................ 96
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) .................................... 97
15.7.1 Frequently Asked Questions: ................................................................................ 97
15.8 Automatic Reclosing (Table 4) .......................................................................................... 98
15.8.1 Frequently‐asked Questions .......................................................................................... 98
15.9 Examples of Evidence of Compliance ......................................................................... 99
15.9.1 Frequently Asked Questions: .................................................................................... 99
References .................................................................................................................................. 101
Figures ......................................................................................................................................... 103
Figure 1: Typical Transmission System ............................................................................. 103
Figure 2: Typical Generation System ................................................................................ 104
Figure 1 & 2 Legend – Components of Protection Systems ....................................................... 105
Appendix A .................................................................................................................................. 106
Appendix B .................................................................................................................................. 109
Protection System Maintenance Standard Drafting Team ................................................. 109
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PRC‐005‐3 Supplementary Reference and FAQ – October 2013
1. Introduction and Summary
Note: This supplementary reference for PRC‐005‐3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC‐005‐1b — Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC‐011‐0 — UVLS System Maintenance and Testing
PRC‐017‐0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs. Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC‐005‐3 will replace
PRC‐005‐2 which combined and replaced PRC‐005, PRC‐008, PRC‐011 and PRC‐017. PRC‐005‐3
adds Automatic Reclosing to PRC‐005‐2. PRC‐005‐2 addressed these directed modifications and
replaces PRC‐005, PRC‐008, PRC‐011 and PRC‐017.
FERC Order 758 further directed that maintenance of reclosing relays that affect the reliable
operation of the Bulk Power System be addressed. PRC‐005‐3 addresses this directive, and,
when approved, will supersede PRC‐005‐2.
This document augments the Supplementary Reference and FAQ previously developed for PRC‐
005‐2 by including discussion relevant to Automatic Reclosing added in PRC‐005‐3.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation ‐ a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed ‐ can result
in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC‐005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC‐005‐3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC‐005‐2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
Protective relays which respond to electrical quantities,
Communications systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC‐005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in‐force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non‐transmission voltage level (Distribution
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 would
apply to this equipment. An example is underfrequency load‐shedding, which is frequently
applied well down into the distribution system to meet PRC‐007‐0.
PRC‐005‐2 replaced the existing PRC‐005, PRC‐008, PRC‐011 and PRC‐017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC‐008 was
constructed quite differently than the original PRC‐005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock‐out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC‐005‐2 replaced PRC‐011, it will be important to make the distinction
between under‐voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC‐011 is now applicable under PRC‐005‐2. An example of an under‐voltage
load‐shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC‐011 are the very same types of
devices needed in PRC‐005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
4
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non‐transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 applies to this
equipment. An example is underfrequency load‐shedding, which is frequently applied well
down into the distribution system to meet PRC‐007‐0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock‐out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non‐BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip‐test requirements. For these devices that are otherwise non‐BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock‐out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC‐005‐2, the drafting team combined legacy standards PRC‐005‐1b, PRC‐008‐
0, PRC‐011‐0, and PRC‐017‐0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
5
The intent of the drafting team is that the legacy standards be reflected in PRC‐005‐2 as
follows:
Applicability of PRC‐005‐1b for Protection Systems relating to non‐generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC‐008‐0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC‐011‐0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC‐017‐0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC‐005‐1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage‐sensing devices.
Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC‐005‐3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the BES
bus located at generating plant substations where the total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at substations
one bus away from generating plants specified in Section 4.2.6.1 when the
substation is less than 10 circuit‐miles from the generating plant substation.
4.2.6.3 Automatic Reclosing applied as an integral part of a SPS specified in Section
4.2.4.
Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
6
a close‐in three‐phase fault present for twice the normal clearing time (capturing a minimum
trip‐close‐trip time delay) does not result in a total loss of gross generation in the
Interconnection exceeding the gross capacity of the largest BES unit within the Balancing
Authority Area where the Automatic Reclosing is applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal‐performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when premature
autoreclosing has the potential to cause generating unit or plant instability. A technical report,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”, is
referenced in PRC‐005‐3 and provides a more detailed discussion of these concerns.
How do I interpret Applicability Section 4.2.6 to determine applicability in the
following examples:
At my generating plant substation, I have a total of 800 MW connected to one voltage level and
200 MW connected to another voltage level. How do I determine my gross capacity? Where
do I consider Automatic Reclosing to be applicable?
Scenario number 1:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 800 MW. The two units are
essentially independent plants.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because 800 MW exceeds the largest single unit in
the BA area.
Gross Capacity
Automatic
Reclosing in scope
BES V
G
800 MW
800 MW
BES V
> 10 mi
G 200 MW
non BES V
[Essentially independent plants]
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Scenario number 2:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is a connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, reclosing into a fault on the BES system could impact the stability of the non‐BES‐
connected generating units. Therefore, the total installed gross generating capacity would be
1000 MW.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
8
Scenario number 3:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation but the generating units
connected at the BES voltage level do not operate independently of the units connected at the
non BES voltage level (e.g., a combined cycle facility where 800 MW of combustion turbines are
connected at a BES voltage level whose exhaust is used to power a 200 MW steam unit
connected to a non BES voltage level. The largest single unit in the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 1000 MW. Therefore,
reclosing into a fault on the BES voltage level would result in a loss of the 800 MW combustion
turbines and subsequently result in the loss of the 200 MW steam unit because of the loss of
the heat source to its boiler.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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Scenario 4
The 800 MW of generation is connected at 345 kV and the 200 MW is connected at 138 kV with
an autotransformer at the generating plant substation connecting the two voltage levels. The
largest single unit in the BA area is 900 MW.
In this case, the total installed gross generating capacity would be 1000 MW and section 4.2.6.1
would be applicable to both the 345 kV Automatic Reclosing Components and the 138 kV
Automatic Reclosing Components, since the total capacity of 1000 MW is larger than the largest
single unit in the BA area.
However, if the 345 kV and the 138 kV systems can be shown to be uncoupled such that the
138 kV reclosing relays will not affect the stability of the 345 kV generating units then the 138
kV Automatic Reclosing Components need not be included per section 4.2.6.1.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BOTH*
* The study detailed in Footnote 1 of the draft standard may eliminate the 138 kV
Automatic Reclosing
Components and/or the 345 kV Automatic Reclosing Components
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
10
Why does 4.2.6.2 specify “10 circuit miles”?
As noted in “Considerations for Maintenance and Testing of Autoreclosing Schemes —
November 2012”, transmission line impedance on the order of one mile away typically provides
adequate impedance to prevent generating unit instability and a 10 mile threshold provides
sufficient margin.
Should I use MVA or MW when determining the installed gross generating plant
capacity?
Be consistent with the rating used by the Balancing Authority for the largest BES generating unit
within their area.
What value should we use for generating plant capacity in 4.2.6.1?
Use the value reported to the Balance Authority for generating plant capacity for planning and
modeling purposes. This can be nameplate or other values based on generating plant
limitations such as boiler or turbine ratings.
What is considered to be “one bus away” from the generation?
The BES voltage level bus is considered to be the generating plant substation bus to which the
generator step‐up transformer is connected. “One bus away” is the next bus, connected by
either a transmission line or transformer.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the low‐
voltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low‐voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2‐2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is unaware
of industry‐recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
11
with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non‐electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2‐2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock‐out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor‐based relays have six significant traits that impact a maintenance
strategy:
Self monitoring capability ‐ the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non‐Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current‐measuring devices, and even the control
circuitry (in the form of software‐latches replacing lock‐out relays, etc.).
Any Protection System component can have self‐monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand‐held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessor‐
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
13
based device that results in a “lock‐out.” Thus, the software‐latch 86 that replaces an electro‐
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and automatic reclosing components are kept in working order and proper operation of
malfunctioning components is restored. A maintenance program for a specific component
includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in‐service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay .
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow‐up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three‐phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
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failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC‐005‐1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC‐005‐3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1‐1 through 1‐5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC‐005‐3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid‐state protective
relays to microprocessor‐based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance‐time‐interval‐clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time‐interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
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management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed‐end process”).
For example, a problem might be identified on a VRLA battery during a six‐month check. In
instances such as one that requiring battery replacement as part of the long‐term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six‐calendar‐month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time‐based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location ‐ for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on‐command or routinely;
the running of these tests can extend the time interval between hands‐on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
TBM – time‐based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
PBM – Performance‐Based Maintenance ‐ intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM‐
developed extended intervals when test failures or in‐service failures occur infrequently.
CBM – condition‐based maintenance – continuously or frequently reported results from
non‐disruptive self‐monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self‐diagnostics. While the term “Condition‐Based‐
Maintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status‐monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored‐basis‐time‐intervals” existing within the standard, the
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explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor‐based Protection System or Automatic Reclosing Components that
perform continuous self‐monitoring verify correct operation of most components within
the device. Self‐monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self‐monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with self‐
monitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non‐disruptive self‐monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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TBM
1
2
3
CBM
PBM
Relationship of time‐based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition‐based Maintenance (R1) and
Performance‐Based Maintenance (R2), in addition to simple time‐based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time‐based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance‐Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off-line by tripping the
transformer’s high-side and low-side circuit breakers. What testing must be done
for this system?
This system is made up of components that are all unmonitored. Assuming a time‐based
Protection System Maintenance Program schedule (as opposed to a Performance‐Based
maintenance program), each component must be maintained per the most frequent hands‐on
activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time‐based. Default time‐based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from time‐
based maintenance. The following factors may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self‐monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition‐based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor‐based relays, self‐monitoring may not include automated
diagnostics of every component within a microprocessor.
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Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance‐Based Maintenance, or
PBM. It is also sometimes referred to as reliability‐centered maintenance, or RCM; but
PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor‐based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition‐based maintenance is the process of gathering and monitoring the information
available from modern microprocessor‐based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self‐monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non‐invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
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provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1‐4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device‐level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1‐4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1‐4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7. Time-Based Versus Condition-Based
Maintenance
Time‐based and condition‐based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time‐based and condition‐based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06‐16‐000) on Mandatory Reliability Standards
for the Bulk‐Power System, directed NERC to submit a modification to PRC‐005‐1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC‐005‐3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition‐based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous ‐ the time interval between verifications is
minutes or seconds. Thus, technically sound, condition‐based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time‐based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on‐site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC‐005‐3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four‐month
inspection was performed in January is due in May, but if performed in March (instead of May)
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would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with an internal alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented Lead‐Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1‐5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead‐acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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Vented Lead‐Acid battery without any alarms connected to SCADA
(unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition‐Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
This response may include tripping, closing, or other control actions.
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely ‐ for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters ‐ this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1‐1 through 1‐5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications‐assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub‐systems of a Protection System that need to be verified are shown.
Non‐distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non‐distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co‐located non‐BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC‐005‐3:
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First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1‐1 is for protective relays,
o Table 1‐2 is for the associated communications systems,
o Table 1‐3 is for current and voltage sensing devices,
o Table 1‐4 is for station dc supply and
o Table 1‐5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make‐up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
Next look within that table for your device and its degree of monitoring. The Tables
have different hands‐on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
This Maintenance activity is the minimum maintenance activity that must be
documented.
If your Performance‐Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands‐on maintenance activity cycles of
this component.
If your Performance‐Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands‐on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
An entity does not have to utilize the extended time intervals made available by this use
of condition‐based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance man‐
hours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
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maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC‐005‐3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC‐005‐3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance‐Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead‐acid,
valve‐regulated lead‐acid, and nickel‐cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC‐005‐3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC‐005‐3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
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properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End‐to‐end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications‐assisted trip scheme. While
this can be interpreted as a GPS‐type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally‐test the dc control circuitry. A documented Real‐time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real‐time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1‐8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology‐ and method‐neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor‐ based relays.
For relay maintenance departments that choose to test microprocessor‐based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor‐ based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time‐overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end‐to‐end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real‐time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not‐to‐exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four‐month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time‐based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance‐Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
Fault protective functions, including distance functions, voltage‐restrained overcurrent
functions, or voltage‐controlled overcurrent functions
Loss‐of‐field relays
Volts‐per‐hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator‐ground relays
Communications‐based Protection Systems such as transfer‐trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out‐of‐step relays
Inadvertent energization protection
Breaker failure protection
For generator step‐up, generator‐connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
Transformer differential relays
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Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal‐conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system‐connected station service transformers be included in
the Applicability. The generator‐connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock‐out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
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distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non‐distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non‐distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC‐005‐1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three‐year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC‐005‐3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on‐site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance‐Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance‐time‐interval‐
clock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time‐interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
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The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC‐005‐3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged‐Fault‐tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be re‐
verified within an ongoing maintenance program. Example – it is not necessary to re‐verify
correct terminal strip wiring on an ongoing basis.
PRC‐005‐3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC‐005‐3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC‐005‐3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
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It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non‐compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in‐service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in‐service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1‐1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto‐generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built‐in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I‐17 (Transmission Relay System
Performance Comparison). Review of the I‐17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
41
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively‐known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self‐testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1‐1 through 1‐5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10‐year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self‐monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
Relay Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
Abnormal Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self‐monitoring capability is ST (for self test).
ST = 0 if there is no self‐monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time‐interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “time‐
interval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time‐interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six‐year interval for the
electromechanical relay, instead of the five‐year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10‐year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
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facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance‐Based Maintenance process may be used to
establish maintenance intervals (PRC‐005 Attachment A Criteria for a Performance‐Based
Protection System Maintenance Program). A Performance‐Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance‐Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance‐Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance‐Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance‐Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001‐2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance‐Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro‐mechanical lock‐out relays;
likewise, one segment cannot be comprised of 60 GE lock‐out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics ‐ Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis ‐ Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
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46
2
z
n 1
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance‐Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance‐Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1‐1 through 1‐5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4% Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
Performance-Based Program Evaluation Example
The 4% performance target was derived as a protection system performance target and was
selected based on the drafting team’s experience and studies performed by several utilities.
This is not derived from the performance of discrete devices. Microprocessor relays and
electromechanical relays have different performance levels. It is not appropriate to compare
these performance levels to each other. The performance of the segment should be compared
to the 4% performance criteria.
In consideration of the use of Performance Based Maintenance (PBM), the user should consider
the effects of extended testing intervals and the established 4% failure rate. In the table shown
below, the segment is 1000 units. As the testing interval (in years) increases, the number of
units tested each year decreases. The number of countable events allowed is 4% of the tested
units. Countable events are the failure of a Component requiring repair or replacement, any
corrective actions performed during the maintenance test on the units within the testing
segment (units per year), or any misoperation attributable to hardware failure or calibration
failure found within the entire segment (1000 units) during the testing year.
Example: 1000 units in the segment with a testing interval of 8 years: The number of units
tested each year will be 125 units. The total allowable countable events equals: 125 X .04 = 5.
This number includes failure of a Component requiring repair or replacement, corrective issues
found during testing, and the total number of misoperations (attributable to hardware or
calibration failure within the testing year) associated with the entire segment of 1000 units.
Example: 1000 units in the segment with a testing interval of 16 years: The number of units
tested each year will be 63 units. The total allowable countable events equals: 63 X .04 = 2.5.
As shown in the above examples, doubling the testing interval reduces the number of
allowable events by half.
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Total number of units in the segment
Failure rate
Testing
Intervals
(Years)
1
2
4
6
8
10
12
14
16
18
20
Units
Per
Year
1000.00
500.00
250.00
166.67
125.00
100.00
83.33
71.43
62.50
55.56
50.00
1000
4.00%
Acceptable Number of
Countable Events per year
40.00
20.00
10.00
6.67
5.00
4.00
3.33
2.86
2.50
2.22
2.00
Yearly Failure Rate
Based on 1000
Units in Segment
4.00%
2.00%
1.00%
0.67%
0.50%
0.40%
0.33%
0.29%
0.25%
0.22%
0.20%
Using the prior year’s data, determine the maximum allowable maintenance interval for each
Segment such that the Segment experiences Countable Events on no more than 4% of the
Components within the Segment, for the greater of either the last 30 Components maintained
or all Components maintained in the previous year.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
49
to the requirements of the Standard. The requirements established for Performance‐Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power‐plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance‐Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance‐Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance‐Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in‐service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re‐calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human‐error is not pertinent data might be in the area of testing “86” lock‐out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial six‐
year interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human‐error caused tripping
incidents. In this example the human‐error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
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Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal‐performing segments in a Performance‐Based Maintenance system. Some examples are
listed below.
The maximum allowable interval, as established by the Performance‐Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
Identifiable sub‐groups of components within the established segment, which have
been identified to be the mal‐performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance‐Based Maintenance program in
order to remain within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal‐performance.
components within the mal‐performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal‐performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC‐004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance‐Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance‐Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock‐reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1‐1‐11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6‐1‐12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock‐reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
51
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance‐Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance‐changing criteria.
Similarly, Functional Entities that want to establish a condition‐based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands‐on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1‐4).
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Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE‐HEA lock‐out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six‐year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
53
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
54
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V‐insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper‐sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
55
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real‐time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12‐
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
56
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested / year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
Failure
Rate
(=F/U)
(F)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
57
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off‐line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real‐time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built‐in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity‐accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
58
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note ‐ a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
59
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
60
10. Overlapping the Verification of Sections of the
Protection System
Tables 1‐1 through 1‐5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
Time‐based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1‐1 through 1‐5;
Monitoring as described in Tables 1‐1 through 1‐5;
A Performance‐Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto‐polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
61
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time‐interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance‐related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
62
11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC‐018‐1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC‐002‐1 and PRC‐018‐1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
63
12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single self‐
monitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non‐microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
64
regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenance‐
activity‐time‐interval‐clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up‐rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC‐005‐3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC‐005‐3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC‐005‐3 to remove
such component(s). Obviously, prudence would dictate that an “out‐of‐service” device is truly
made inactive. There are no record requirements listed in PRC‐005‐3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC‐005‐3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC‐005‐3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
65
The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
66
13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self‐monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self‐monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands‐on
maintenance requirement), the manufacturers of the microprocessor‐based self‐monitoring
components in the Protection System should publish for the user a document or map that
shows:
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
67
13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology‐neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early‐generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC‐005‐3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non‐electrical inputs are excluded.
Non‐microprocessor based equipment is treated differently than microprocessor‐based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
Non‐microprocessor devices must be tested with voltage and/or current applied to the
device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber‐optic Hall‐effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
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protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real‐time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
Another method for proving the voltage and/or current‐sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current‐sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all‐inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi‐meters, voltmeter, clamp‐on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re‐check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi‐pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt‐meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual‐intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This six‐
year tripping requirement can be completed as easily as tracking the Real‐time Fault‐clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit‐interrupting device should not be confused with a motor‐operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high‐speed auto‐closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred‐tripping
device without the use of communications equipment. If this high‐speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring‐operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock‐out relay
(86) that may exist in any particular trip scheme. If the lock‐out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six‐year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non‐BES interrupting devices are not required. Normally‐open contacts
that are not used to pass a trip signal and normally‐closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC‐005‐2, other alarming relay control circuits,
(i.e., SF‐6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard‐wired trip circuitry with other methods of trip‐signal conveyance
such as fiber‐optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber‐optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is
unaware of industry‐recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐
17, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC‐005‐3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC‐005‐3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1‐5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC‐005‐3 includes high‐speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non‐BES circuit breaker that is tripped via a Protection
System to which PRC‐005‐3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non‐black‐start) radial Loads but has a trip that originates from an under‐frequency
(81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non‐BES breaker that is tripped via a Protection
System to which PRC‐005‐3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non‐black‐start) radial Loads but has a trip that originates from a BES 115KV
line relay.
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock‐out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock‐out (86) (or auxiliary (94)) relay and the
non‐BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non‐BES circuit breaker that is tripped via a
Protection System to which PRC‐005‐3 applies, such as the generator field breaker and low‐side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non‐BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
The differential relay must be verified.
The current signals to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally‐closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
Protective relays which respond to electrical quantities,
Communications Systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1‐4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance‐Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance‐changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC‐005‐3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger ‐ The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery ‐ Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1‐4.
Emerging Technologies ‐ Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1‐4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1‐4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor‐based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one‐ to two‐
second delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp‐range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc‐supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor‐controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
Internal ohmic measurements of the cells and units of lead‐acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1‐4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve‐regulated lead‐acid, vented
lead‐acid, or nickel‐cadmium) and the maintenance activity chosen.
For example, if you have a valve‐regulated lead‐acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the six‐
month interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead‐acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six‐months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve‐regulated lead‐acid (VRLA) batteries and vented lead‐acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer‐supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead‐acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel‐cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve‐regulated lead‐acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1‐4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell‐to‐cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1‐4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1‐4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell‐to‐cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1‐4 by a Performance‐Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1‐4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1‐4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot‐checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally‐accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel‐cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel‐cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel‐cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel‐cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel‐cadmium batteries,
there are no significantly measurable properties of the nickel‐cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1‐4(c)
(Protection System Station dc supply Using nickel‐cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check‐off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check‐off per battery bank is sufficient for documentation, as long as the single check‐
off attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC‐005‐3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve‐Regulated Lead‐Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead‐Acid (VLA)
batteries were unable to be used on this new type of lead‐acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188‐2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1‐4. In cases where individual cells in a multi‐cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1‐4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead‐acid (VLA) and nickel‐cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1‐4. Because
the electrolyte level in valve‐regulated lead‐acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1‐4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved‐quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve‐regulated lead‐acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1‐4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead‐acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry‐out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1‐4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six‐month test” at Row 4 on Table 1‐4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1‐4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six‐month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline ‐ others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six‐month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1‐4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self‐
monitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1‐4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1‐4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1‐4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1‐4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1‐4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1‐4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1‐4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications‐assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications‐assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communications‐
assisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber‐optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on‐site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
On‐off power‐line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check‐back test from one terminal.
Systems which use frequency‐shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss‐of‐guard indication or alarm. For frequency‐shift power‐line carrier systems, the
guard signal level meter can also be checked.
Hard‐wired pilot wire line Protection Systems typically have pilot‐wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
On‐off power‐line carrier systems can be shown to be operational by automated
periodic power‐line carrier check‐back tests with remote alarming of failures.
Systems which use a frequency‐shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss‐of‐guard alarm or low signal level alarm.
Hard‐wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot‐wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements, including signal‐to‐noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four‐month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
Power Line Carrier (PLC) ‐ The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical‐electrical signal format converters are the associated
communications equipment
Figure 1‐2, A‐1 and A‐2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
An on‐off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check‐back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre‐determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1‐1 through 1‐5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto‐polling system; the only
requirement is that the alarm be brought to the action‐site within 24 hours. This effectively
makes manned‐stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned‐station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non‐manned‐
station, which is that if the monitored point has an alarm that is auto‐reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail‐safe “form‐b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1‐1. Voltage and current‐sensing devices have the same maintenance activity and
interval as Table 1‐3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
Verify the trip path between the relay and lock‐out and/or auxiliary tripping device(s).
Verify operation of any lock‐out and/or auxiliary tripping device(s) used in the trip
circuit.
No verification of trip path required between the lock‐out (and/or auxiliary tripping
device) and the non‐BES interrupting device.
No verification of trip path required between the relay and trip coil for circuits that have
no lock‐out and/or auxiliary tripping device(s).
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non‐BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load‐Shed relay and lock‐out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock‐out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under‐frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non‐BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock‐out relay. While many failures of these distributed system circuit breakers (or
non‐BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non‐BES device, such as a battery bank that serves both a BES circuit breaker and a non‐BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during under‐
frequency or under‐voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load‐generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC‐005‐3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC‐005‐3.
15.8.1 Frequently-asked Questions
Automatic Reclosing is a control, not a protective function; why then is Automatic
Reclosing maintenance included in the Protection System Maintenance Program
(PSMP)?
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes (separates) the Automatic Reclosing
from the Protection System. Automatic Reclosing is included in the PSMP because it is a more
pragmatic approach as compared to creating a parallel and essentially identical ‘Control System
Maintenance Program’ for the two Automatic Reclosing component types.
Our maintenance practice consists of initiating the Automatic Reclosing relay and
confirming the breaker closes properly and the close signal is released. This practice
verifies the control circuitry associated with Automatic Reclosing. Do you agree?”
The described task partially verifies the control circuit maintenance activity. To meet the
control circuit maintenance activity, responsible entities need to verify, upon initiation, that the
reclosing relay does not issue a premature closing command. As noted on page 12 of the
SAMS/SPCS report, the concern being addressed within the standard is premature
autoreclosing that has the potential to cause generating unit or plant instability. Reclosing
applications have many variations, responsible entities will need to verify the applicability of
associated supervision/conditional logic and the reclosing relay operation; then verify the
conditional logic or that the reclosing relay performs in a manner that does not result in a
premature closing command being issued.
Some examples of conditions which can result in a premature closing command are: an
improper supervision or conditional logic input which provides a false state and allows the
reclosing relay to issue an improper close command based on incorrect conditions (i.e. voltage
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supervision, equipment status, sync window verification); timers utilized for closing actuation
or reclosing arming/disarming circuitry which could allow the reclosing relay to issue an
improper close command; a reclosing relay output contact failure which could result in a made‐
up‐close condition / failure‐to‐release condition.
Why was a close-in three phase fault present for twice the normal clearing time
chosen for the Automatic Reclosing exclusion? It exceeds TPL requirements and
ignores the breaker closing time in a trip-close-trip sequence, thus making the
exclusion harder to attain.
This condition represents a situation where a close signal is issued with no time delay or with
less time delay than is intended, such as if a reclosing contact is welded closed. This failure
mode can result in a minimum trip‐close‐trip sequence with the two faults cleared in primary
protection operating time, and the open time between faults equal to the breaker closing cycle
time. The sequence for this failure mode results in system impact equivalent to a high‐speed
autoreclosing sequence with no delay added in the autoreclosing logic. It represents a failure
mode which must be avoided because it exceeds TPL requirements.
Do we have to test the various breaker closing circuit interlocks and controls such
as anti-pump?
These components are not specifically addressed within Table 4, and need not be individually
tested. They are indirectly verified by performing the Automatic Reclosing control circuitry
verification as established in Table 4.
For Automatic Reclosing that is not part of an SPS, do we have to close the circuit
breaker periodically?
No. For this application, you need only to verify that the Automatic Reclosing, upon initiation,
does not issue a premature closing command. This activity is concerned only with assuring that
a premature close does not occur, and cause generating plant instability.
For Automatic Reclosing that is part of an SPS, do we have to close the circuit
breaker periodically?
Yes. In this application, successful closing is a necessary portion of the SPS, and must be
verified.
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC standards that could, at times,
fulfill evidence requirements of this standard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
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Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check‐off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC‐016 could work for the activity tracking requirements
under this PRC‐005‐3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
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References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor‐Based
Transmission‐Line Protective Relays, Part I ‐ Explanation of the Statistics, and Part II ‐
Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016‐6
PWRD and 96WM 127‐1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR‐ 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve‐
Regulated Lead‐Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead‐Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45‐2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented Lead‐
Acid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR‐100248, 1006757, August 2002.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
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PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” ‐ Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
19. “Considerations for Maintenance and Testing of Autoreclosing Schemes,” NERC
System Analysis and Modeling Subcommittee and NERC System Protection and
Control Subcommittee, November 2012
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Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
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Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC‐005‐2, and also
may not be all‐inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
104
Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Component of
Protection System
Includes
Excludes
Devices that use non‐electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync‐check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber‐optic systems that
carry a trip signal as well as hard‐
wired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
Tele‐protection equipment used
Communications
to convey specific information, in
systems necessary
the form of analog or digital
for correct operation
signals, necessary for the correct
of protective
operation of protective functions.
functions
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
4
5
Additional information can be found in References
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
105
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A‐1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two‐terminal pilot protection scheme to protect for line Faults, and to avoid over‐
tripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self‐monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self‐monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
106
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on‐off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check‐back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A‐2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
107
contacts of a small telephone‐type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check‐back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone‐type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally‐occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC‐005‐3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front‐panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay‐carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
108
Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle Ashton
Tri‐State G&T
Forrest Brock
Western Farmers Electric Cooperative
Aaron Feathers
Pacific Gas and Electric Company
Sam Francis
Oncor Electric Delivery
David Harper
NRG Texas Maintenance Services
James M. Kinney
FirstEnergy Corporation
Mark Lucas
ComEd
Kristina Marriott
ENOSERV
Al McMeekin
NERC
Michael Palusso
Southern California Edison
John Schecter
American Electric Power
William D. Shultz
Southern Company Generation
Eric A. Udren
Quanta Technology
Scott Vaughan
City of Roseville Electric Department
Matthew Westrich
American Transmission Company
Philip B. Winston
Southern Company Transmission
John A. Zipp
ITC Holdings
PRC‐005‐3 Supplementary Reference and FAQ – October 2013
109
``
Supplementary Reference
and FAQ
PRC-005-3 Protection System Maintenance
April October 2013
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Table of Contents
Table of Contents .............................................................................................................................ii
1. Introduction and Summary ......................................................................................................... 1
2. Need for Verifying Protection System Performance .................................................................. 2
2.1 Existing NERC Standards for Protection System Maintenance and Testing ............. 2
2.2 Protection System Definition ............................................................................................ 3
2.3 Applicability of New Protection System Maintenance Standards ................................ 3
2.3.1 Frequently Asked Questions: ........................................................................................ 4
2.4.1 Frequently Asked Questions: ........................................................................................ 6
3. Protection System and Automatic Reclosing Product Generations ......................................... 13
4. Definitions ................................................................................................................................. 15
4.1 Frequently Asked Questions: ......................................................................................... 16
5. Time‐Based Maintenance (TBM) Programs .............................................................................. 18
5.1 Maintenance Practices .................................................................................................... 18
5.1.1 Frequently Asked Questions: .................................................................................. 20
5.2 Extending Time-Based Maintenance ......................................................................... 21
5.2.1 Frequently Asked Questions: .................................................................................. 22
6. Condition‐Based Maintenance (CBM) Programs ...................................................................... 23
6.1 Frequently Asked Questions: .............................................................................................. 23
7. Time‐Based Versus Condition‐Based Maintenance .................................................................. 25
7.1 Frequently Asked Questions: ......................................................................................... 25
8. Maximum Allowable Verification Intervals............................................................................... 31
8.1 Maintenance Tests ........................................................................................................... 31
8.1.1 Table of Maximum Allowable Verification Intervals ............................................ 31
ii
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4 ................. 33
8.1.3 Frequently Asked Questions: .................................................................................. 34
8.2 Retention of Records ....................................................................................................... 39
8.2.1 Frequently Asked Questions: .................................................................................. 39
8.3 Basis for Table 1 Intervals .............................................................................................. 41
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays .................... 42
9. Performance‐Based Maintenance Process ............................................................................... 45
9.1 Minimum Sample Size ..................................................................................................... 46
9.2 Frequently Asked Questions: ......................................................................................... 49
10. Overlapping the Verification of Sections of the Protection System ....................................... 61
10.1 Frequently Asked Questions: ....................................................................................... 61
11. Monitoring by Analysis of Fault Records ................................................................................ 62
11.1 Frequently Asked Questions: ....................................................................................... 63
12. Importance of Relay Settings in Maintenance Programs ....................................................... 64
12.1 Frequently Asked Questions: ....................................................................................... 64
13. Self‐Monitoring Capabilities and Limitations.......................................................................... 67
13.1 Frequently Asked Questions: ....................................................................................... 68
14. Notification of Protection System or Automatic Reclosing Failures ....................................... 69
15. Maintenance Activities ........................................................................................................... 70
15.1 Protective Relays (Table 1-1) ...................................................................................... 70
15.1.1 Frequently Asked Questions: ................................................................................ 70
15.2 Voltage & Current Sensing Devices (Table 1-3) ................................................... 70
15.2.1 Frequently Asked Questions: ................................................................................ 72
15.3 Control circuitry associated with protective functions (Table 1-5) .................... 73
15.3.1 Frequently Asked Questions: ................................................................................ 75
iii
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
15.4 Batteries and DC Supplies (Table 1-4) ................................................................... 77
15.4.1 Frequently Asked Questions: ................................................................................ 77
15.5 Associated communications equipment (Table 1-2) ................................................ 92
15.5.1 Frequently Asked Questions: ................................................................................ 93
15.6 Alarms (Table 2) ............................................................................................................ 96
15.6.1 Frequently Asked Questions: ................................................................................ 96
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3) .................................... 97
15.7.1 Frequently Asked Questions: ................................................................................ 97
15.8 Automatic Reclosing (Table 4) .......................................................................................... 98
15.8.1 Frequently‐asked Questions .......................................................................................... 98
15.9 Examples of Evidence of Compliance ......................................................................... 99
15.9.1 Frequently Asked Questions: .................................................................................... 99
References .................................................................................................................................. 101
Figures ......................................................................................................................................... 103
Figure 1: Typical Transmission System ............................................................................. 103
Figure 2: Typical Generation System ................................................................................ 104
Figure 1 & 2 Legend – Components of Protection Systems ....................................................... 105
Appendix A .................................................................................................................................. 106
Appendix B .................................................................................................................................. 109
Protection System Maintenance Standard Drafting Team ................................................. 109
iv
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
1. Introduction and Summary
Note: This supplementary reference for PRC‐005‐3 is neither mandatory nor enforceable.
NERC currently has four Reliability Standards that are mandatory and enforceable in the United
States and Canada and address various aspects of maintenance and testing of Protection and
Control Systems.
These standards are:
PRC‐005‐1b — Transmission and Generation Protection System Maintenance and Testing
PRC‐008‐0 — Underfrequency Load Shedding Equipment Maintenance Programs
PRC‐011‐0 — UVLS System Maintenance and Testing
PRC‐017‐0 — Special Protection System Maintenance and Testing
While these standards require that applicable entities have a maintenance program for
Protection Systems, and that these entities must be able to demonstrate they are carrying out
such a program, there are no specifics regarding the technical requirements for Protection
System maintenance programs. Furthermore, FERC Order 693 directed additional
modifications respective to Protection System maintenance programs. PRC‐005‐3 will replace
PRC‐005‐2 which combined and replaced PRC‐005, PRC‐008, PRC‐011 and PRC‐017. PRC‐005‐3
adds Automatic Reclosing to PRC‐005‐2. PRC‐005‐2 addressed these directed modifications and
replaces PRC‐005, PRC‐008, PRC‐011 and PRC‐017.
FERC Order 758 further directed that maintenance of reclosing relays that affect the reliable
operation of the Bulk Power System be addressed. PRC‐005‐3 addresses this directive, and,
when approved, will supersede PRC‐005‐2.
This document augments the Supplementary Reference and FAQ previously developed for PRC‐
005‐2 by including discussion relevant to Automatic Reclosing added in PRC‐005‐3.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
1
2. Need for Verifying Protection System Performance
Protective relays have been described as silent sentinels, and do not generally demonstrate
their performance until a Fault or other power system problem requires that they operate to
protect power system Elements, or even the entire Bulk Electric System (BES). Lacking Faults,
switching operations or system problems, the Protection Systems may not operate, beyond
static operation, for extended periods. A Misoperation ‐ a false operation of a Protection
System or a failure of the Protection System to operate, as designed, when needed ‐ can result
in equipment damage, personnel hazards, and wide‐area Disturbances or unnecessary
customer outages. Maintenance or testing programs are used to determine the performance
and availability of Protection Systems.
Typically, utilities have tested Protection Systems at fixed time intervals, unless they had some
incidental evidence that a particular Protection System was not behaving as expected. Testing
practices vary widely across the industry. Testing has included system functionality, calibration
of measuring devices, and correctness of settings. Typically, a Protection System must be
visited at its installation site and, in many cases, removed from service for this testing.
Fundamentally, a Reliability Standard for Protection System Maintenance and Testing requires
the performance of the maintenance activities that are necessary to detect and correct
plausible age and service related degradation of the Protection System components, such that a
properly built and commissioned Protection System will continue to function as designed over
its service life.
Similarly station batteries, which are an important part of the station dc supply, are not called
upon to provide instantaneous dc power to the Protection System until power is required by
the Protection System to operate circuit breakers or interrupting devices to clear Faults or to
isolate equipment.
2.1 Existing NERC Standards for Protection System Maintenance and Testing
For critical BES protection functions, NERC standards have required that each utility or asset
owner define a testing program. The starting point is the existing Standard PRC‐005, briefly
restated as follows:
Purpose: To document and implement programs for the maintenance of all Protection Systems
affecting the reliability of the Bulk Electric System (BES) so that these Protection Systems are
kept in working order.
PRC‐005‐3 is not specific on where the boundaries of the Protection Systems lie. However, the
definition of Protection System in the NERC Glossary of Terms used in Reliability Standards
indicates what must be included as a minimum.
At the beginning of the project to develop PRC‐005‐2, the definition of Protection System was:
Protective relays, associated communications Systems, voltage and current sensing devices,
station batteries and dc control circuitry.
Applicability: Owners of generation and transmission Protection Systems.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
2
Requirements: The owner shall have a documented maintenance program with test intervals.
The owner must keep records showing that the maintenance was performed at the specified
intervals.
2.2 Protection System Definition
The most recently approved definition of Protection Systems is:
Protective relays which respond to electrical quantities,
Communications systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
2.3 Applicability of New Protection System Maintenance Standards
The BES purpose is to transfer bulk power. The applicability language has been changed from
the original PRC‐005:
“...affecting the reliability of the Bulk Electric System (BES)…”
To the present language:
“…that are installed for the purpose of detecting Faults on BES Elements (lines, buses,
transformers, etc.).”
The drafting team intends that this standard will follow with any definition of the Bulk Electric
System. There should be no ambiguity; if the Element is a BES Element, then the Protection
System protecting that Element should then be included within this standard. If there is
regional variation to the definition, then there will be a corresponding regional variation to the
Protection Systems that fall under this standard.
There is no way for the Standard Drafting Team to know whether a specific 230KV line, 115KV
line (even 69KV line), for example, should be included or excluded. Therefore, the team set the
clear intent that the standard language should simply be applicable to Protection Systems for
BES Elements.
The BES is a NERC defined term that, from time to time, may undergo revisions. Additionally,
there may even be regional variations that are allowed in the present and future definitions.
See the NERC Glossary of Terms for the present, in‐force definition. See the applicable Regional
Reliability Organization for any applicable allowed variations.
While this standard will undergo revisions in the future, this standard will not attempt to keep
up with revisions to the NERC definition of BES, but, rather, simply make BES Protection
Systems applicable.
The Standard is applied to Generator Owners (GO) and Transmission Owners (TO) because GOs
and TOs have equipment that is BES equipment. The standard brings in Distribution Providers
(DP) because, depending on the station configuration of a particular substation, there may be
Protection System equipment installed at a non‐transmission voltage level (Distribution
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
3
Provider equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 would
apply to this equipment. An example is underfrequency load‐shedding, which is frequently
applied well down into the distribution system to meet PRC‐007‐0.
PRC‐005‐2 replaced the existing PRC‐005, PRC‐008, PRC‐011 and PRC‐017. Much of the original
intent of those standards was carried forward whenever it was possible to continue the intent
without a disagreement with FERC Order 693. For example, the original PRC‐008 was
constructed quite differently than the original PRC‐005. The drafting team agrees with the
intent of this and notes that distributed tripping schemes would have to exhibit multiple
failures to trip before they would prove to be significant, as opposed to a single failure to trip
of, for example, a transmission Protection System Bus Differential lock‐out relay. While many
failures of these distribution breakers could add up to be significant, it is also believed that
distribution breakers are operated often on just Fault clearing duty; and, therefore, the
distribution circuit breakers are operated at least as frequently as stipulated in any requirement
in this standard.
Additionally, since PRC‐005‐2 replaced PRC‐011, it will be important to make the distinction
between under‐voltage Protection Systems that protect individual Loads and Protection
Systems that are UVLS schemes that protect the BES. Any UVLS scheme that had been
applicable under PRC‐011 is now applicable under PRC‐005‐2. An example of an under‐voltage
load‐shedding scheme that is not applicable to this standard is one in which the tripping action
was intended to prevent low distribution voltage to a specific Load from a Transmission system
that was intact except for the line that was out of service, as opposed to preventing a Cascading
outage or Transmission system collapse.
It had been correctly noted that the devices needed for PRC‐011 are the very same types of
devices needed in PRC‐005.
Thus, a standard written for Protection Systems of the BES can easily make the needed
requirements for Protection Systems, and replace some other standards at the same time.
2.3.1 Frequently Asked Questions:
What exactly is the BES, or Bulk Electric System?
BES is the abbreviation for Bulk Electric System. BES is a term in the Glossary of Terms used in
Reliability Standards, and is not being modified within this draft standard.
NERC's approved definition of Bulk Electric System is:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, Interconnections with neighboring Systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission Facilities serving only
Load with one transmission source are generally not included in this definition.
The BES definition is presently undergoing the process of revision.
Each regional entity implements a definition of the Bulk Electric System that is based on this
NERC definition; in some cases, supplemented by additional criteria. These regional definitions
have been documented and provided to FERC as part of a June 14, 2007 Informational Filing.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
4
Why is Distribution Provider included within the Applicable Entities and as a
responsible entity within several of the requirements? Wouldn’t anyone having
relevant Facilities be a Transmission Owner?
Depending on the station configuration of a particular substation, there may be Protection
System equipment installed at a non‐transmission voltage level (Distribution Provider
equipment) that is wholly or partially installed to protect the BES. PRC‐005‐3 applies to this
equipment. An example is underfrequency load‐shedding, which is frequently applied well
down into the distribution system to meet PRC‐007‐0.
We have an under voltage load-shedding (UVLS) system in place that prevents one
of our distribution substations from supplying extremely low voltage in the case of a
specific transmission line outage. The transmission line is part of the BES. Does this
mean that our UVLS system falls within this standard?
The situation, as stated, indicates that the tripping action was intended to prevent low
distribution voltage to a specific Load from a Transmission System that was intact, except for
the line that was out of service, as opposed to preventing Cascading outage or Transmission
System Collapse.
This standard is not applicable to this UVLS.
We have a UFLS or UVLS scheme that sheds the necessary Load through
distribution-side circuit breakers and circuit reclosers.
Do the trip-test
requirements for circuit breakers apply to our situation?
No. Distributed tripping schemes would have to exhibit multiple failures to trip before they
would prove to be significant, as opposed to a single failure to trip of, for example, a
transmission Protection System bus differential lock‐out relay. While many failures of these
distribution breakers could add up to be significant, it is also believed that distribution breakers
are operated often on just Fault clearing duty; and, therefore, the distribution circuit breakers
are operated at least as frequently as any requirements that might have appeared in this
standard.
We have a UFLS scheme that, in some locales, sheds the necessary Load through
non-BES circuit breakers and, occasionally, even circuit switchers. Do the trip-test
requirements for circuit breakers apply to our situation?
If your “non‐BES circuit breaker” has been brought into this standard by the inclusion of UFLS
requirements, and otherwise would not have been brought into this standard, then the answer
is that there are no trip‐test requirements. For these devices that are otherwise non‐BES
assets, these tripping schemes would have to exhibit multiple failures to trip before they would
prove to be as significant as, for example, a single failure to trip of a transmission Protection
System bus differential lock‐out relay.
How does the “Facilities” section of “Applicability” track with the standards that will
be retired once PRC-005-2 becomes effective?
In establishing PRC‐005‐2, the drafting team combined legacy standards PRC‐005‐1b, PRC‐008‐
0, PRC‐011‐0, and PRC‐017‐0. The merger of the subject matter of these standards is reflected
in Applicability 4.2.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
5
The intent of the drafting team is that the legacy standards be reflected in PRC‐005‐2 as
follows:
Applicability of PRC‐005‐1b for Protection Systems relating to non‐generator
elements of the BES is addressed in 4.2.1;
Applicability of PRC‐008‐0 for underfrequency load shedding systems is addressed in
4.2.2;
Applicability of PRC‐011‐0 for undervoltage load shedding relays is addressed in
4.2.3;
Applicability of PRC‐017‐0 for Special Protection Systems is addressed in 4.2.4;
Applicability of PRC‐005‐1b for Protection Systems for BES generators is addressed in
4.2.5.
2.4 Applicable Relays
The NERC Glossary definition has a Protection System including relays, dc supply, current and
voltage sensing devices, dc control circuitry and associated communications circuits. The relays
to which this standard applies are those protective relays that respond to electrical quantities
and provide a trip output to trip coils, dc control circuitry or associated communications
equipment. This definition extends to IEEE Device No. 86 (lockout relay) and IEEE Device No. 94
(tripping or trip‐free relay), as these devices are tripping relays that respond to the trip signal of
the protective relay that processed the signals from the current and voltage‐sensing devices.
Relays that respond to non‐electrical inputs or impulses (such as, but not limited to, vibration,
pressure, seismic, thermal or gas accumulation) are not included.
Automatic Reclosing is addressed in PRC‐005‐3 by explicitly addressing them outside the
definition of Protection System. The specific locations for applicable Automatic Reclosing are
addressed in Applicability Section 4.2.6.
2.4.1 Frequently Asked Questions:
Are power circuit reclosers, reclosing relays, closing circuits and auto-restoration
schemes covered in this Standard?
Yes. Automatic Reclosing includes reclosing relays and the associated dc control circuitry.
Section 4.2.6 of the Applicability specifically limits the applicable reclosing relays to:
4.2.6 Automatic Reclosing
4.2.6.1 Automatic Reclosing applied on the terminals of Elements connected to the BES
bus located at generating plant substations where the total installed gross
generating plant capacity is greater than the gross capacity of the largest BES
generating unit within the Balancing Authority Area.
4.2.6.2 Automatic Reclosing applied on the terminals of all BES Elements at substations
one bus away from generating plants specified in Section 4.2.6.1 when the
substation is less than 10 circuit‐miles from the generating plant substation.
4.2.6.3 Automatic Reclosing applied as an integral part of a SPS specified in Section
4.2.4.
Further, Footnote 1 to Applicability Section 4.2.6 establishes that Automatic Reclosing
addressed in 4.2.6.1 and 4.2.6.2 may be excluded if the equipment owner can demonstrate that
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
6
a close‐in three‐phase fault present for twice the normal clearing time (capturing a minimum
trip‐close‐trip time delay) does not result in a total loss of gross generation in the
Interconnection exceeding the gross capacity of the largest BES unit within the Balancing
Authority Area where the Automatic Reclosing is applied.
The Applicability as detailed above was recommended by the NERC System Analysis and
Modeling Subcommittee (SAMS) after a lengthy review of the use of reclosing within the BES.
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an
operating convenience, and that automatic reclosing mal‐performance affects BES reliability
only when the reclosing is part of a Special Protection System, or when premature
autoreclosing has the potential to cause generating unit or plant instability. A technical report,
“Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012”, is
referenced in PRC‐005‐3 and provides a more detailed discussion of these concerns.
How do I interpret Applicability Section 4.2.6 to determine applicability in the
following examples:
At my generating plant substation, I have a total of 800 MW connected to one voltage level and
200 MW connected to another voltage level. How do I determine my gross capacity? Where
do I consider Automatic Reclosing to be applicable?
Scenario number 1:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 800 MW. The two units are
essentially independent plants.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because 800 MW exceeds the largest single unit in
the BA area.
Gross Capacity
Automatic
Reclosing in scope
BES V
G
800 MW
800 MW
BES V
>
10 mi
G 200 MW
non BES V
[Essentially independent plants]
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
7
Scenario number 2:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is a connection between the two buses
locally or within 10 circuit miles from the generating plant substation. The largest single unit in
the BA area is 750 MW.
In this case, reclosing into a fault on the BES system could impact the stability of the non‐BES‐
connected generating units. Therefore, the total installed gross generating capacity would be
1000 MW.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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Scenario number 3:
The 800 MW of generation is connected to a BES voltage level bus, the 200 MW unit is
connected to a non‐BES voltage level bus, and there is no connection between the two buses
locally or within 10 circuit miles from the generating plant substation but the generating units
connected at the BES voltage level do not operate independently of the units connected at the
non BES voltage level (e.g., a combined cycle facility where 800 MW of combustion turbines are
connected at a BES voltage level whose exhaust is used to power a 200 MW steam unit
connected to a non BES voltage level. The largest single unit in the BA area is 750 MW.
In this case, the total installed gross generating capacity would be 1000 MW. Therefore,
reclosing into a fault on the BES voltage level would result in a loss of the 800 MW combustion
turbines and subsequently result in the loss of the 200 MW steam unit because of the loss of
the heat source to its boiler.
The BES voltage level bus is considered to be the bus to which the 800 MW of generation is
connected. Any BES Automatic Reclosing at this location, as well as other locations within 10
circuit miles, is considered to be applicable because total of 1000 MW exceeds the largest
single unit in the BA area. However, the Automatic Reclosing on the non‐BES voltage level bus is
not applicable.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BES V
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Scenario 4
The 800 MW of generation is connected at 345 kV and the 200 MW is connected at 138 kV with
an autotransformer at the generating plant substation connecting the two voltage levels. The
largest single unit in the BA area is 900 MW.
In this case, the total installed gross generating capacity would be 1000 MW and section 4.2.6.1
would be applicable to both the 345 kV Automatic Reclosing Components and the 138 kV
Automatic Reclosing Components, since the total capacity of 1000 MW is larger than the largest
single unit in the BA area.
However, if the 345 kV and the 138 kV systems can be shown to be uncoupled such that the
138 kV reclosing relays will not affect the stability of the 345 kV generating units then the 138
kV Automatic Reclosing Components need not be included per section 4.2.6.1.
Gross Capacity
1000 MW
Automatic
Reclosing in scope
BOTH*
* The study detailed in Footnote 1 of the draft standard may eliminate the 138 kV Automatic Reclosing
Components and/or the 345 kV Automatic Reclosing Components
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Why does 4.2.6.2 specify “10 circuit miles”?
As noted in “Considerations for Maintenance and Testing of Autoreclosing Schemes —
November 2012”, transmission line impedance on the order of one mile away typically provides
adequate impedance to prevent generating unit instability and a 10 mile threshold provides
sufficient margin.
Should I use MVA or MW when determining the installed gross generating plant
capacity?
Be consistent with the rating used by the Balancing Authority for the largest BES generating unit
within their area.
What value should we use for generating plant capacity in 4.2.6.1?
Use the value reported to the Balance Authority for generating plant capacity for planning and
modeling purposes. This can be nameplate or other values based on generating plant
limitations such as boiler or turbine ratings.
What is considered to be “one bus away” from the generation?
The BES voltage level bus is considered to be the generating plant substation bus to which the
generator step‐up transformer is connected. “One bus away” is the next bus, connected by
either a transmission line or transformer.
I use my protective relays only as sources of metered quantities and breaker status
for SCADA and EMS through a substation distributed RTU or data concentrator to
the control center. What are the maintenance requirements for the relays?
This standard addresses Protection Systems that are installed for the purpose of detecting
Faults on BES Elements (lines, buses, transformers, etc.). Protective relays, providing only the
functions mentioned in the question, are not included.
Are Reverse Power Relays installed on the low-voltage side of distribution banks
considered to be components of “Protection Systems that are installed for the
purpose of detecting Faults on BES Elements (lines, buses, transformers, etc.)”?
Reverse power relays are often installed to detect situations where the transmission source
becomes deenergized and the distribution bank remains energized from a source on the low‐
voltage side of the transformer and the settings are calculated based on the charging current of
the transformer from the low‐voltage side. Although these relays may operate as a result of a
fault on a BES element, they are not ‘installed for the purpose of detecting’ these faults.
Is a Sudden Pressure Relay an auxiliary tripping relay?
No. IEEE C37.2‐2008 assigns the Device No. 94 to auxiliary tripping relays. Sudden pressure
relays are assigned Device No. 63. Sudden pressure relays are presently excluded from the
standard because it does not utilize voltage and/or current measurements to determine
anomalies. Devices that use anything other than electrical detection means are excluded. The
trip path from a sudden pressure device is a part of the Protection System control circuitry. The
sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is unaware
of industry‐recognized testing protocol for the sensing elements. The SDT believes that
Protection Systems that trip (or can trip) the BES should be included. This position is consistent
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with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐17, and
understands this to be consistent with the position of FERC staff.
My mechanical device does not operate electrically and does not have calibration
settings; what maintenance activities apply?
You must conduct a test(s) to verify the integrity of any trip circuit that is a part of a Protection
System. This standard does not cover circuit breaker maintenance or transformer
maintenance. The standard also does not presently cover testing of devices, such as sudden
pressure relays (63), temperature relays (49), and other relays which respond to mechanical
parameters, rather than electrical parameters. There is an expectation that Fault pressure
relays and other non‐electrically initiated devices may become part of some maintenance
standard. This standard presently covers trip paths. It might seem incongruous to test a trip
path without a present requirement to test the device; and, thus, be arguably more work for
nothing. But one simple test to verify the integrity of such a trip path could be (but is not
limited to) a voltage presence test, as a dc voltage monitor might do if it were installed
monitoring that same circuit.
The standard specifically mentions auxiliary and lock-out relays.
auxiliary tripping relay?
What is an
An auxiliary relay, IEEE Device No. 94, is described in IEEE Standard C37.2‐2008 as: “A device
that functions to trip a circuit breaker, contactor, or equipment; to permit immediate tripping
by other devices; or to prevent immediate reclosing of a circuit interrupter if it should open
automatically, even though its closing circuit is maintained closed.”
What is a lock-out relay?
A lock‐out relay, IEEE Device No. 86, is described in IEEE Standard C37.2 as: “A device that trips
and maintains the associated equipment or devices inoperative until it is reset by an operator,
either locally or remotely.”
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3. Protection System and Automatic Reclosing
Product Generations
The likelihood of failure and the ability to observe the operational state of a critical Protection
System and Automatic Reclosing both depend on the technological generation of the relays, as
well as how long they have been in service. Unlike many other transmission asset groups,
protection and control systems have seen dramatic technological changes spanning several
generations. During the past 20 years, major functional advances are primarily due to the
introduction of microprocessor technology for power system devices, such as primary
measuring relays, monitoring devices, control Systems, and telecommunications equipment.
Modern microprocessor‐based relays have six significant traits that impact a maintenance
strategy:
Self monitoring capability ‐ the processors can check themselves, peripheral circuits, and
some connected substation inputs and outputs, such as trip coil continuity. Most relay
users are aware that these relays have self monitoring, but are not focusing on exactly
what internal functions are actually being monitored. As explained further below, every
element critical to the Protection System must be monitored, or else verified
periodically.
Ability to capture Fault records showing how the Protection System responded to a
Fault in its zone of protection, or to a nearby Fault for which it is required not to
operate.
Ability to meter currents and voltages, as well as status of connected circuit breakers,
continuously during non‐Fault times. The relays can compute values, such as MW and
MVAR line flows, that are sometimes used for operational purposes, such as SCADA.
Data communications via ports that provide remote access to all of the results of
Protection System monitoring, recording and measurement.
Ability to trip or close circuit breakers and switches through the Protection System
outputs, on command from remote data communications messages, or from relay front
panel button requests.
Construction from electronic components, some of which have shorter technical life or
service life than electromechanical components of prior Protection System generations.
There have been significant advances in the technology behind the other components of
Protection Systems. Microprocessors are now a part of battery chargers, associated
communications equipment, voltage and current‐measuring devices, and even the control
circuitry (in the form of software‐latches replacing lock‐out relays, etc.).
Any Protection System component can have self‐monitoring and alarming capability, not just
relays. Because of this technology, extended time intervals can find their way into all
components of the Protection System.
This standard also recognizes the distinct advantage of using advanced technology to justifiably
defer or even eliminate traditional maintenance. Just as a hand‐held calculator does not
require routine testing and calibration, neither does a calculation buried in a microprocessor‐
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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based device that results in a “lock‐out.” Thus, the software‐latch 86 that replaces an electro‐
mechanical 86 does not require routine trip testing. Any trip circuitry associated with the “soft
86” would still need applicable verification activities performed, but the actual “86” does not
have to be “electrically operated” or even toggled.
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4. Definitions
Protection System Maintenance Program (PSMP) — An ongoing program by which Protection
System and automatic reclosing components are kept in working order and proper operation of
malfunctioning components is restored. A maintenance program for a specific component
includes one or more of the following activities:
Verify — Determine that the component is functioning correctly.
Monitor — Observe the routine in‐service operation of the component.
Test — Apply signals to a component to observe functional performance or output
behavior, or to diagnose problems.
Inspect — Detect visible signs of component failure, reduced performance and
degradation.
Calibrate — Adjust the operating threshold or measurement accuracy of a measuring
element to meet the intended performance requirement.
Automatic Reclosing –
Includes the following Components:
Reclosing relay
Control circuitry associated with the reclosing relay .
Unresolved Maintenance Issue – A deficiency identified during a maintenance activity that
causes the component to not meet the intended performance, cannot be corrected during the
maintenance interval, and requires follow‐up corrective action.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Component Type – Either any one of the five specific elements of the Protection System
definition or any one of the two specific elements of the Automatic Reclosing definition.
Component – A Component is any individual discrete piece of equipment included in a
Protection System or in Automatic Reclosing, including but not limited to a protective relay,
reclosing relay, or current sensing device. The designation of what constitutes a control circuit
Component is dependent upon how an entity performs and tracks the testing of the control
circuitry. Some entities test their control circuits on a breaker basis whereas others test their
circuitry on a local zone of protection basis. Thus, entities are allowed the latitude to designate
their own definitions of control circuit Components. Another example of where the entity has
some discretion on determining what constitutes a single Component is the voltage and current
sensing devices, where the entity may choose either to designate a full three‐phase set of such
devices or a single device as a single Component.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
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failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
4.1 Frequently Asked Questions:
Why does PRC-005-3 not specifically require maintenance and testing procedures,
as reflected in the previous standard, PRC-005-1?
PRC‐005‐1 does not require detailed maintenance and testing procedures, but instead requires
summaries of such procedures, and is not clear on what is actually required. PRC‐005‐3
requires a documented maintenance program, and is focused on establishing requirements
rather than prescribing methodology to meet those requirements. Between the activities
identified in the Tables 1‐1 through 1‐5, Table 2, Table 3, and Table 4 (collectively the “Tables”),
and the various components of the definition established for a “Protection System
Maintenance Program,” PRC‐005‐3 establishes the activities and time basis for a Protection
System Maintenance Program to a level of detail not previously required.
Please clarify what is meant by “restore” in the definition of maintenance.
The description of “restore” in the definition of a Protection System Maintenance Program
addresses corrective activities necessary to assure that the component is returned to working
order following the discovery of its failure or malfunction. The Maintenance Activities specified
in the Tables do not present any requirements related to Restoration; R5 of the standard does
require that the entity “shall demonstrate efforts to correct any identified Unresolved
Maintenance Issues.” Some examples of restoration (or correction of Unresolved Maintenance
Issues) include, but are not limited to, replacement of capacitors in distance relays to bring
them to working order; replacement of relays, or other Protection System components, to bring
the Protection System to working order; upgrade of electromechanical or solid‐state protective
relays to microprocessor‐based relays following the discovery of failed components.
Restoration, as used in this context, is not to be confused with restoration rules as used in
system operations. Maintenance activity necessarily includes both the detection of problems
and the repairs needed to eliminate those problems. This standard does not identify all of the
Protection System problems that must be detected and eliminated, rather it is the intent of this
standard that an entity determines the necessary working order for their various devices, and
keeps them in working order. If an equipment item is repaired or replaced, then the entity can
restart the maintenance‐time‐interval‐clock, if desired; however, the replacement of
equipment does not remove any documentation requirements that would have been required
to verify compliance with time‐interval requirements. In other words, do not discard
maintenance data that goes to verify your work.
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
Please clarify what is meant by “…demonstrate efforts to correct an Unresolved
Maintenance Issue…”; why not measure the completion of the corrective action?
Management of completion of the identified Unresolved Maintenance Issue is a complex topic
that falls outside of the scope of this standard. There can be any number of supply, process and
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management problems that make setting repair deadlines impossible. The SDT specifically
chose the phrase “demonstrate efforts to correct” (with guidance from NERC Staff) because of
the concern that many more complex Unresolved Maintenance Issues might require greater
than the remaining maintenance interval to resolve (and yet still be a “closed‐end process”).
For example, a problem might be identified on a VRLA battery during a six‐month check. In
instances such as one that requiring battery replacement as part of the long‐term resolution, it
is highly unlikely that the battery could be replaced in time to meet the six‐calendar‐month
requirement for this maintenance activity. The SDT does not believe entities should be found in
violation of a maintenance program requirement because of the inability to complete a
remediation program within the original maintenance interval. The SDT does believe corrective
actions should be timely, but concludes it would be impossible to postulate all possible
remediation projects; and, therefore, impossible to specify bounding time frames for resolution
of all possible Unresolved Maintenance Issues, or what documentation might be sufficient to
provide proof that effective corrective action is being undertaken.
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5. Time-Based Maintenance (TBM) Programs
Time‐based maintenance is the process in which Protection System and Automatic Reclosing
Components are maintained or verified according to a time schedule. The scheduled program
often calls for technicians to travel to the physical site and perform a functional test on
Protection System components. However, some components of a TBM program may be
conducted from a remote location ‐ for example, tripping a circuit breaker by communicating a
trip command to a microprocessor relay to determine if the entire Protection System tripping
chain is able to operate the breaker. Similarly, all Protection System and Automatic Reclosing
Components can have the ability to remotely conduct tests, either on‐command or routinely;
the running of these tests can extend the time interval between hands‐on maintenance
activities.
5.1 Maintenance Practices
Maintenance and testing programs often incorporate the following types of maintenance
practices:
TBM – time‐based maintenance – externally prescribed maximum maintenance or
testing intervals are applied for components or groups of components. The intervals
may have been developed from prior experience or manufacturers’ recommendations.
The TBM verification interval is based on a variety of factors, including experience of the
particular asset owner, collective experiences of several asset owners who are members
of a country or regional council, etc. The maintenance intervals are fixed and may range
in number of months or in years.
TBM can include review of recent power system events near the particular terminal.
Operating records may verify that some portion of the Protection System has operated
correctly since the last test occurred. If specific protection scheme components have
demonstrated correct performance within specifications, the maintenance test time
clock can be reset for those components.
PBM – Performance‐Based Maintenance ‐ intervals are established based on analytical
or historical results of TBM failure rates on a statistically significant population of similar
components. Some level of TBM is generally followed. Statistical analyses accompanied
by adjustments to maintenance intervals are used to justify continued use of PBM‐
developed extended intervals when test failures or in‐service failures occur infrequently.
CBM – condition‐based maintenance – continuously or frequently reported results from
non‐disruptive self‐monitoring of components demonstrate operational status as those
components remain in service. Whatever is verified by CBM does not require manual
testing, but taking advantage of this requires precise technical focus on exactly what
parts are included as part of the self‐diagnostics. While the term “Condition‐Based‐
Maintenance” (CBM) is no longer used within the standard itself, it is important to note
that the concepts of CBM are a part of the standard (in the form of extended time
intervals through status‐monitoring). These extended time intervals are only allowed (in
the absence of PBM) if the condition of the device is monitored (CBM). As a
consequence of the “monitored‐basis‐time‐intervals” existing within the standard, the
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explanatory discussions within this Supplementary Reference concerned with CBM will
remain in this reference and are discussed as CBM.
Microprocessor‐based Protection System or Automatic Reclosing Components that
perform continuous self‐monitoring verify correct operation of most components within
the device. Self‐monitoring capabilities may include battery continuity, float voltages,
unintentional grounds, the ac signal inputs to a relay, analog measuring circuits,
processors and memory for measurement, protection, and data communications, trip
circuit monitoring, and protection or data communications signals (and many, many
more measurements). For those conditions, failure of a self‐monitoring routine
generates an alarm and may inhibit operation to avoid false trips. When internal
components, such as critical output relay contacts, are not equipped with self‐
monitoring, they can be manually tested. The method of testing may be local or
remote, or through inherent performance of the scheme during a system event.
The TBM is the overarching maintenance process of which the other types are subsets. Unlike
TBM, PBM intervals are adjusted based on good or bad experiences. The CBM verification
intervals can be hours, or even milliseconds between non‐disruptive self‐monitoring checks
within or around components as they remain in service.
TBM, PBM, and CBM can be combined for individual components, or within a complete
Protection System. The following diagram illustrates the relationship between various types of
maintenance practices described in this section. In the Venn diagram, the overlapping regions
show the relationship of TBM with PBM historical information and the inherent continuous
monitoring offered through CBM.
This figure shows:
Region 1: The TBM intervals that are increased based on known reported operational
condition of individual components that are monitoring themselves.
Region 2: The TBM intervals that are adjusted up or down based on results of analysis of
maintenance history of statistically significant population of similar products that have
been subject to TBM.
Region 3: Optimal TBM intervals based on regions 1 and 2.
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TBM
1
2
3
CBM
PBM
Relationship of time‐based maintenance types
5.1.1 Frequently Asked Questions:
The standard seems very complicated, and is difficult to understand.
simplified?
Can it be
Because the standard is establishing parameters for condition‐based Maintenance (R1) and
Performance‐Based Maintenance (R2), in addition to simple time‐based Maintenance, it does
appear to be complicated. At its simplest, an entity needs to ONLY perform time‐based
maintenance according to the unmonitored rows of the Tables. If an entity then wishes to take
advantage of monitoring on its Protection System components and its available lengthened
time intervals, then it may, as long as the component has the listed monitoring attributes. If an
entity wishes to use historical performance of its Protection System components to perform
Performance‐Based Maintenance, then R2 applies.
Please see the following diagram, which provides a “flow chart” of the standard.
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We have an electromechanical (unmonitored) relay that has a trip output to a
lockout relay (unmonitored) which trips our transformer off-line by tripping the
transformer’s high-side and low-side circuit breakers. What testing must be done
for this system?
This system is made up of components that are all unmonitored. Assuming a time‐based
Protection System Maintenance Program schedule (as opposed to a Performance‐Based
maintenance program), each component must be maintained per the most frequent hands‐on
activities listed in the Tables.
5.2 Extending Time-Based Maintenance
All maintenance is fundamentally time‐based. Default time‐based intervals are commonly
established to assure proper functioning of each component of the Protection System, when
data on the reliability of the components is not available other than observations from time‐
based maintenance. The following factors may influence the established default intervals:
If continuous indication of the functional condition of a component is available (from
relays or chargers or any self‐monitoring device), then the intervals may be extended, or
manual testing may be eliminated. This is referred to as condition‐based maintenance
or CBM. CBM is valid only for precisely the components subject to monitoring. In the
case of microprocessor‐based relays, self‐monitoring may not include automated
diagnostics of every component within a microprocessor.
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Previous maintenance history for a group of components of a common type may
indicate that the maintenance intervals can be extended, while still achieving the
desired level of performance. This is referred to as Performance‐Based Maintenance, or
PBM. It is also sometimes referred to as reliability‐centered maintenance, or RCM; but
PBM is used in this document.
Observed proper operation of a component may be regarded as a maintenance
verification of the respective component or element in a microprocessor‐based device.
For such an observation, the maintenance interval may be reset only to the degree that
can be verified by data available on the operation. For example, the trip of an
electromechanical relay for a Fault verifies the trip contact and trip path, but only
through the relays in series that actually operated; one operation of this relay cannot
verify correct calibration.
Excessive maintenance can actually decrease the reliability of the component or system. It is
not unusual to cause failure of a component by removing it from service and restoring it. The
improper application of test signals may cause failure of a component. For example, in
electromechanical overcurrent relays, test currents have been known to destroy convolution
springs.
In addition, maintenance usually takes the component out of service, during which time it is not
able to perform its function. Cutout switch failures, or failure to restore switch position,
commonly lead to protection failures.
5.2.1 Frequently Asked Questions:
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
The maintenance and testing requirements (R5) (in essence) state “…shall demonstrate efforts
to correct any identified Unresolved Maintenance Issues.” The type of corrective activity is not
stated; however it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity could very well ask for
documentation showing status of your corrective actions.
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6. Condition-Based Maintenance (CBM) Programs
Condition‐based maintenance is the process of gathering and monitoring the information
available from modern microprocessor‐based relays and other intelligent electronic devices
(IEDs) that monitor Protection System or Automatic Reclosing elements. These devices
generate monitoring information during normal operation, and the information can be assessed
at a convenient location remote from the substation. The information from these relays and
IEDs is divided into two basic types:
1. Information can come from background self‐monitoring processes, programmed by the
manufacturer, or by the user in device logic settings. The results are presented by alarm
contacts or points, front panel indications, and by data communications messages.
2. Information can come from event logs, captured files, and/or oscillographic records for
Faults and Disturbances, metered values, and binary input status reports. Some of
these are available on the device front panel display, but may be available via data
communications ports. Large files of Fault information can only be retrieved via data
communications. These results comprise a mass of data that must be further analyzed
for evidence of the operational condition of the Protection System.
Using these two types of information, the user can develop an effective maintenance program
carried out mostly from a central location remote from the substation. This approach offers the
following advantages:
Non‐invasive Maintenance: The system is kept in its normal operating state, without
human intervention for checking. This reduces risk of damage, or risk of leaving the
system in an inoperable state after a manual test. Experience has shown that keeping
human hands away from equipment known to be working correctly enhances reliability.
Virtually Continuous Monitoring: CBM will report many hardware failure problems for
repair within seconds or minutes of when they happen. This reduces the percentage of
problems that are discovered through incorrect relaying performance. By contrast, a
hardware failure discovered by TBM may have been there for much of the time interval
between tests, and there is a good chance that some devices will show health problems
by incorrect operation before being caught in the next test round. The frequent or
continuous nature of CBM makes the effective verification interval far shorter than any
required TBM maximum interval. To use the extended time intervals available through
Condition Based Maintenance, simply look for the rows in the Tables that refer to
monitored items.
6.1 Frequently Asked Questions:
My microprocessor relays and dc circuit alarms are contained on relay panels in a
24-hour attended control room. Does this qualify as an extended time interval
condition-based (monitored) system?
Yes, provided the station attendant (plant operator, etc.) monitors the alarms and other
indications (comparable to the monitoring attributes) and reports them within the given time
limits that are stated in the criteria of the Tables.
When documenting the basis for inclusion of components into the appropriate levels
of monitoring, as per Requirement R1 (Part 1.4) of the standard, is it necessary to
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provide this documentation about the device by listing of every component and the
specific monitoring attributes of each device?
No. While maintaining this documentation on the device level would certainly be permissible,
it is not necessary. Global statements can be made to document appropriate levels of
monitoring for the entire population of a component type or portion thereof.
For example, it would be permissible to document the conclusion that all BES substation dc
supply battery chargers are monitored by stating the following within the program description:
“All substation dc supply battery chargers are considered monitored and subject to the
rows for monitored equipment of Table 1‐4 requirements, as all substation dc supply
battery chargers are equipped with dc voltage alarms and ground detection alarms that are
sent to the manned control center.”
Similarly, it would be acceptable to use a combination of a global statement and a device‐level
list of exclusions. Example:
“Except as noted below, all substation dc supply battery chargers are considered monitored
and subject to the rows for monitored equipment of Table 1‐4 requirements, as all
substation dc supply battery chargers are equipped with dc voltage alarms and ground
detection alarms that are sent to the manned control center. The dc supply battery
chargers of Substation X, Substation Y, and Substation Z are considered unmonitored and
subject to the rows for unmonitored equipment in Table 1‐4 requirements, as they are not
equipped with ground detection capability.”
Regardless whether this documentation is provided by device listing of monitoring attributes,
by global statements of the monitoring attributes of an entire population of component types,
or by some combination of these methods, it should be noted that auditors may request
supporting drawings or other documentation necessary to validate the inclusion of the
device(s) within the appropriate level of monitoring. This supporting background information
need not be maintained within the program document structure, but should be retrievable if
requested by an auditor.
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7. Time-Based Versus Condition-Based
Maintenance
Time‐based and condition‐based (or monitored) maintenance programs are both acceptable, if
implemented according to technically sound requirements. Practical programs can employ a
combination of time‐based and condition‐based maintenance. The standard requirements
introduce the concept of optionally using condition monitoring as a documented element of a
maintenance program.
The Federal Energy Regulatory Commission (FERC), in its Order Number 693 Final Rule, dated
March 16, 2007 (18 CFR Part 40, Docket No. RM06‐16‐000) on Mandatory Reliability Standards
for the Bulk‐Power System, directed NERC to submit a modification to PRC‐005‐1b that includes
a requirement that maintenance and testing of a Protection System must be carried out within
a maximum allowable interval that is appropriate to the type of the Protection System and its
impact on the reliability of the Bulk Power System. Accordingly, this Supplementary Reference
Paper refers to the specific maximum allowable intervals in PRC‐005‐3. The defined time limits
allow for longer time intervals if the maintained component is monitored.
A key feature of condition‐based monitoring is that it effectively reduces the time delay
between the moment of a protection failure and time the Protection System or Automatic
Reclosing owner knows about it, for the monitored segments of the Protection System. In some
cases, the verification is practically continuous ‐ the time interval between verifications is
minutes or seconds. Thus, technically sound, condition‐based verification, meets the
verification requirements of the FERC order even more effectively than the strictly time‐based
tests of the same system components.
The result is that:
This NERC standard permits utilities to use a technically sound approach and to take advantage
of remote monitoring, data analysis, and control capabilities of modern Protection System and
Automatic Reclosing Components to reduce the need for periodic site visits and invasive testing
of components by on‐site technicians. This periodic testing must be conducted within the
maximum time intervals specified in the Tables of PRC‐005‐3.
7.1 Frequently Asked Questions:
What is a Calendar Year?
Calendar Year ‐ January 1 through December 31 of any year. As an example, if an event
occurred on June 17, 2009 and is on a “One Calendar Year Interval,” the next event would have
to occur on or before December 31, 2010.
Please provide an example of “4 Calendar Months”.
If a maintenance activity is described as being needed every four Calendar Months then it is
performed in a (given) month and due again four months later. For example a battery bank is
inspected in month number 1 then it is due again before the end of the month number5. And
specifically consider that you perform your battery inspection on January 3, 2010 then it must
be inspected again before the end of May. Another example could be that a four‐month
inspection was performed in January is due in May, but if performed in March (instead of May)
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
25
would still be due four months later therefore the activity is due again July. Basically every “four
Calendar Months” means to add four months from the last time the activity was performed.
Please provide an example of the unmonitored versus other levels of monitoring
available?
An unmonitored Protection System has no monitoring and alarm circuits on the Protection
System components. A Protection System component that has monitoring attributes but no
alarm output connected is considered to be unmonitored.
A monitored Protection System or an individual monitored component of a Protection System
has monitoring and alarm circuits on the Protection System components. The alarm circuits
must alert, within 24 hours, a location wherein corrective action can be initiated. This location
might be, but is not limited to, an Operations Center, Dispatch Office, Maintenance Center or
even a portable SCADA system.
There can be a combination of monitored and unmonitored Protection Systems within any
given scheme, substation or plant; there can also be a combination of monitored and
unmonitored components within any given Protection System.
Example #1: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with an internal alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarming. (monitored)
Instrumentation transformers, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented Lead‐Acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, and the trip circuit is not monitored. (unmonitored)
Given the particular components and conditions, and using Table 1 and Table 2, the
particular components have maximum activity intervals of:
Every four calendar months, inspect:
Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system).
Every 18 calendar months, verify/inspect the following:
Battery bank ohmic values to station battery baseline (if performance tests are not
opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
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Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power System input values seen by the microprocessor
protective relay
Verify that current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be initiated
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained as detailed in Table 1‐5
of the standard under the ‘Unmonitored Control Circuitry Associated with Protective
Functions" section’
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #2: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with integral alarm that is not connected to SCADA.
(unmonitored)
Current and voltage signal values, with no monitoring, connected as inputs to that relay.
(unmonitored)
A vented lead‐acid battery with a low voltage alarm for the station dc supply voltage
and an unintentional grounds detection alarm connected to SCADA. (monitoring varies)
A circuit breaker with a trip coil, with no circuits monitored. (unmonitored)
Given the particular components and conditions, and using the Table 1 (Maximum
Allowable Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and
Monitoring), the particular components have maximum activity intervals of:
Every four calendar months, inspect:
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Electrolyte level (station dc supply voltage and unintentional ground detection is
being maintained more frequently by the monitoring system)
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Cell condition of all individual battery cells (where visible)
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Every six calendar years, verify/perform the following:
Verify operation of the relay inputs and outputs that are essential to proper
functioning of the Protection System
Verify acceptable measurement of power system input values as seen by the relays
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Battery performance test (if internal ohmic tests are not opted)
Every 12 calendar years, verify the following:
Current and voltage signal values are provided to the protective relays
Protection System component monitoring for the battery system signals are conveyed
to a location where corrective action can be initiated
All trip paths in the control circuitry associated with protective functions through the
trip coil(s) of the circuit breakers or other interrupting devices
Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions" section
Auxiliary outputs not in a trip path (i.e., annunciation or DME input) are not required,
by this standard, to be checked
Example #3: A combination of monitored and unmonitored components within a given
Protection System might be:
A microprocessor relay with alarm connected to SCADA to alert 24‐hr staffed
operations center; it has internal self diagnosis and alarms. (monitored)
Current and voltage signal values, with monitoring, connected as inputs to that
relay (monitored)
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Vented Lead‐Acid battery without any alarms connected to SCADA
(unmonitored)
Circuit breaker with a trip coil, with no circuits monitored (unmonitored)
Given the particular components, conditions, and using the Table 1 (Maximum Allowable
Testing Intervals and Maintenance Activities) and Table 2 (Alarming Paths and Monitoring),
the particular components shall have maximum activity intervals of:
Every four calendar months, verify/inspect the following:
Station dc supply voltage
For unintentional grounds
Electrolyte level
Every 18 calendar months, verify/inspect the following:
Battery bank trending of ohmic values or other measurements indicative of battery
performance to station battery baseline (if performance tests are not opted)
Battery charger float voltage
Battery rack integrity
Battery continuity
Battery terminal connection resistance
Battery cell‐to‐cell resistance (where available to measure)
Condition of all individual battery cells (where visible)
Every six calendar years, perform/verify the following:
Battery performance test (if internal ohmic tests or other measurements indicative of
battery performance are not opted)
Verify that each trip coil is able to operate the circuit breaker, interrupting device, or
mitigating device
For electromechanical lock‐out relays, electrical operation of electromechanical trip
Every 12 calendar years, verify the following:
The microprocessor relay alarm signals are conveyed to a location where corrective
action can be taken
Microprocessor relay settings are as specified
Operation of the microprocessor’s relay inputs and outputs that are essential to
proper functioning of the Protection System
Acceptable measurement of power system input values seen by the microprocessor
protective relay
Verify all trip paths in the control circuitry associated with protective functions
through the trip coil(s) of the circuit breakers or other interrupting devices
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Auxiliary outputs that are in the trip path shall be maintained, as detailed in Table 1‐5
of the standard under the Unmonitored Control Circuitry Associated with Protective
Functions section
Auxiliary outputs not in a trip path (i.e. annunciation or DME input) are not required,
by this standard, to be checked
Why do components have different maintenance activities and intervals if they are
monitored?
The intent behind different activities and intervals for monitored equipment is to allow less
frequent manual intervention when more information is known about the condition of
Protection System components. Condition‐Based Maintenance is a valuable asset to improve
reliability.
Can all components in a Protection System be monitored?
No. For some components in a Protection System, monitoring will not be relevant. For
example, a battery will always need some kind of inspection.
We have a 30-year-old oil circuit breaker with a red indicating lamp on the
substation relay panel that is illuminated only if there is continuity through the
breaker trip coil. There is no SCADA monitor or relay monitor of this trip coil. The
line protection relay package that trips this circuit breaker is a microprocessor relay
that has an integral alarm relay that will assert on a number of conditions that
includes a loss of power to the relay. This alarm contact connects to our SCADA
system and alerts our 24-hour operations center of relay trouble when the alarm
contact closes. This microprocessor relay trips the circuit breaker only and does not
monitor trip coil continuity or other things such as trip current. Are the components
monitored or not? How often must I perform maintenance?
The protective relay is monitored and can be maintained every 12 years, or when an
Unresolved Maintenance Issue arises. The control circuitry can be maintained every 12 years.
The circuit breaker trip coil(s) has to be electrically operated at least once every six years.
What is a mitigating device?
A mitigating device is the device that acts to respond as directed by a Special Protection
System. It may be a breaker, valve, distributed control system, or any variety of other devices.
This response may include tripping, closing, or other control actions.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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8. Maximum Allowable Verification Intervals
The maximum allowable testing intervals and maintenance activities show how CBM with
newer device types can reduce the need for many of the tests and site visits that older
Protection System components require. As explained below, there are some sections of the
Protection System that monitoring or data analysis may not verify. Verifying these sections of
the Protection System or Automatic Reclosing requires some persistent TBM activity in the
maintenance program. However, some of this TBM can be carried out remotely ‐ for example,
exercising a circuit breaker through the relay tripping circuits using the relay remote control
capabilities can be used to verify function of one tripping path and proper trip coil operation, if
there has been no Fault or routine operation to demonstrate performance of relay tripping
circuits.
8.1 Maintenance Tests
Periodic maintenance testing is performed to ensure that the protection and control system is
operating correctly after a time period of field installation. These tests may be used to ensure
that individual components are still operating within acceptable performance parameters ‐ this
type of test is needed for components susceptible to degraded or changing characteristics due
to aging and wear. Full system performance tests may be used to confirm that the total
Protection System functions from measurement of power system values, to properly identifying
Fault characteristics, to the operation of the interrupting devices.
8.1.1 Table of Maximum Allowable Verification Intervals
Table 1 (collectively known as Table 1, individually called out as Tables 1‐1 through 1‐5), Table
2, Table 3, and Table 4 in the standard specify maximum allowable verification intervals for
various generations of Protection Systems and Automatic Reclosing and categories of
equipment that comprise these systems. The right column indicates maintenance activities
required for each category.
The types of components are illustrated in Figures 1 and 2 at the end of this paper. Figure 1
shows an example of telecommunications‐assisted transmission Protection System comprising
substation equipment at each terminal and a telecommunications channel for relaying between
the two substations. Figure 2 shows an example of a generation Protection System. The
various sub‐systems of a Protection System that need to be verified are shown.
Non‐distributed UFLS, UVLS, and SPS are additional categories of Table 1 that are not illustrated
in these figures. Non‐distributed UFLS, UVLS and SPS all use identical equipment as Protection
Systems in the performance of their functions; and, therefore, have the same maintenance
needs.
Distributed UFLS and UVLS Systems, which use local sensing on the distribution System and trip
co‐located non‐BES interrupting devices, are addressed in Table 3 with reduced maintenance
activities.
While it is easy to associate protective relays to multiple levels of monitoring, it is also true that
most of the components that can make up a Protection System can also have technological
advancements that place them into higher levels of monitoring.
To use the Maintenance Activities and Intervals Tables from PRC‐005‐3:
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First find the Table associated with your component. The tables are arranged in the
order of mention in the definition of Protection System;
o Table 1‐1 is for protective relays,
o Table 1‐2 is for the associated communications systems,
o Table 1‐3 is for current and voltage sensing devices,
o Table 1‐4 is for station dc supply and
o Table 1‐5 is for control circuits.
o Table 2, is for alarms; this was broken out to simplify the other tables.
o Table 3 is for components which make‐up distributed UFLS and UVLS Systems.
o Table 4 is for Automatic Reclosing.
Next look within that table for your device and its degree of monitoring. The Tables
have different hands‐on maintenance activities prescribed depending upon the degree
to which you monitor your equipment. Find the maintenance activity that applies to the
monitoring level that you have on your piece of equipment.
This Maintenance activity is the minimum maintenance activity that must be
documented.
If your Performance‐Based Maintenance (PBM) plan requires more activities, then you
must perform and document to this higher standard. (Note that this does not apply
unless you utilize PBM.)
After the maintenance activity is known, check the maximum maintenance interval; this
time is the maximum time allowed between hands‐on maintenance activity cycles of
this component.
If your Performance‐Based Maintenance plan requires activities more often than the
Tables maximum, then you must perform and document those activities to your more
stringent standard. (Note that this does not apply unless you utilize PBM.)
Any given component of a Protection System can be determined to have a degree of
monitoring that may be different from another component within that same Protection
System. For example, in a given Protection System it is possible for an entity to have a
monitored protective relay and an unmonitored associated communications system;
this combination would require hands‐on maintenance activity on the relay at least
once every 12 years and attention paid to the communications system as often as every
four months.
An entity does not have to utilize the extended time intervals made available by this use
of condition‐based monitoring. An easy choice to make is to simply utilize the
unmonitored level of maintenance made available in each of the Tables. While the
maintenance activities resulting from this choice would require more maintenance man‐
hours, the maintenance requirements may be simpler to document and the resulting
maintenance plans may be easier to create.
For each Protection System Component, Table 1 shows maximum allowable testing intervals for
the various degrees of monitoring. For each Automatic Reclosing Component, Table 4 shows
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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maximum allowable testing intervals for the various degrees of monitoring. These degrees of
monitoring, or levels, range from the legacy unmonitored through a system that is more
comprehensively monitored.
It has been noted here that an entity may have a PSMP that is more stringent than PRC‐005‐3.
There may be any number of reasons that an entity chooses a more stringent plan than the
minimums prescribed within PRC‐005‐3, most notable of which is an entity using performance
based maintenance methodology. If an entity has a Performance‐Based Maintenance program,
then that plan must be followed, even if the plan proves to be more stringent than the
minimums laid out in the Tables.
8.1.2 Additional Notes for Tables 1-1 through 1-5, Table 3, and Table 4
1. For electromechanical relays, adjustment is required to bring measurement accuracy
within the tolerance needed by the asset owner. Microprocessor relays with no remote
monitoring of alarm contacts, etc, are unmonitored relays and need to be verified
within the Table interval as other unmonitored relays but may be verified as functional
by means other than testing by simulated inputs.
2. Microprocessor relays typically are specified by manufacturers as not requiring
calibration, but acceptable measurement of power system input values must be verified
(verification of the Analog to Digital [A/D] converters) within the Table intervals. The
integrity of the digital inputs and outputs that are used as protective functions must be
verified within the Table intervals.
3. Any Phasor Measurement Unit (PMU) function whose output is used in a Protection
System or SPS (as opposed to a monitoring task) must be verified as a component in a
Protection System.
4. In addition to verifying the circuitry that supplies dc to the Protection System, the owner
must maintain the station dc supply. The most widespread station dc supply is the
station battery and charger. Unlike most Protection System components, physical
inspection of station batteries for signs of component failure, reduced performance, and
degradation are required to ensure that the station battery is reliable enough to deliver
dc power when required. IEEE Standards 450, 1188, and 1106 for vented lead‐acid,
valve‐regulated lead‐acid, and nickel‐cadmium batteries, respectively (which are the
most commonly used substation batteries on the NERC BES) have been developed as an
important reference source of maintenance recommendations. The Protection System
owner might want to follow the guidelines in the applicable IEEE recommended
practices for battery maintenance and testing, especially if the battery in question is
used for application requirements in addition to the protection and control demands
covered under this standard. However, the Standard Drafting Team has tailored the
battery maintenance and testing guidelines in PRC‐005‐3 for the Protection System
owner which are application specific for the BES Facilities. While the IEEE
recommendations are all encompassing, PRC‐005‐3 is a more economical approach
while addressing the reliability requirements of the BES.
5. Aggregated small entities might distribute the testing of the population of UFLS/UVLS
systems, and large entities will usually maintain a portion of these systems in any given
year. Additionally, if relatively small quantities of such systems do not perform
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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properly, it will not affect the integrity of the overall program. Thus, these distributed
systems have decreased requirements as compared to other Protection Systems.
6. Voltage & current sensing device circuit input connections to the Protection System
relays can be verified by (but not limited to) comparison of measured values on live
circuits or by using test currents and voltages on equipment out of service for
maintenance. The verification process can be automated or manual. The values should
be verified to be as expected (phase value and phase relationships are both equally
important to verify).
7. “End‐to‐end test,” as used in this Supplementary Reference, is any testing procedure
that creates a remote input to the local communications‐assisted trip scheme. While
this can be interpreted as a GPS‐type functional test, it is not limited to testing via GPS.
Any remote scheme manipulation that can cause action at the local trip path can be
used to functionally‐test the dc control circuitry. A documented Real‐time trip of any
given trip path is acceptable in lieu of a functional trip test. It is possible, with sufficient
monitoring, to be able to verify each and every parallel trip path that participated in any
given dc control circuit trip. Or another possible solution is that a single trip path from a
single monitored relay can be verified to be the trip path that successfully tripped during
a Real‐time operation. The variations are only limited by the degree of engineering and
monitoring that an entity desires to pursue.
8. A/D verification may use relay front panel value displays, or values gathered via data
communications. Groupings of other measurements (such as vector summation of bus
feeder currents) can be used for comparison if calibration requirements assure
acceptable measurement of power system input values.
9. Notes 1‐8 attempt to describe some testing activities; they do not represent the only
methods to achieve these activities, but rather some possible methods. Technological
advances, ingenuity and/or industry accepted techniques can all be used to satisfy
maintenance activity requirements; the standard is technology‐ and method‐neutral in
most cases.
8.1.3 Frequently Asked Questions:
What is meant by “Verify that settings are as specified” maintenance activity in
Table 1-1?
Verification of settings is an activity directed mostly towards microprocessor‐ based relays.
For relay maintenance departments that choose to test microprocessor‐based relays in the
same manner as electromechanical relays are tested, the testing process sometimes requires
that some specific functions be disabled. Later tests might enable the functions previously
disabled, but perhaps still other functions or logic statements were then masked out. It is
imperative that, when the relay is placed into service, the settings in the relay be the settings
that were intended to be in that relay or as the standard states “…settings are as specified.”
Many of the microprocessor‐ based relays available today have software tools which provide
this functionality and generate reports for this purpose.
For evidence or documentation of this requirement, a simple recorded acknowledgement that
the settings were checked to be as specified is sufficient.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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The drafting team was careful not to require “…that the relay settings be correct…” because it
was believed that this might then place a burden of proof that the specified settings would
result in the correct intended operation of the interrupting device. While that is a noble
intention, the measurable proof of such a requirement is immense. The intent is that settings
of the component be as specified at the conclusion of maintenance activities, whether those
settings may have “drifted” since the prior maintenance or whether changes were made as part
of the testing process.
Are electromechanical relays included in the “Verify that settings are as specified”
maintenance activity in Table 1-1?
Verification of settings is an activity directed towards the application of protection related
functions of microprocessor based relays. Electromechanical relays require calibration
verification by voltage and/or current injection; and, thus, the settings are verified during
calibration activity. In the example of a time‐overcurrent relay, a minor deviation in time dial,
versus the settings, may be acceptable, as long as the relay calibration is within accepted
tolerances at the injected current amplitudes. A major deviation may require further
investigation, as it could indicate a problem with the relay or an incorrect relay style for the
application.
The verification of phase current and voltage measurements by comparison to other
quantities seems reasonable. How, though, can I verify residual or neutral
currents, or 3V0 voltages, by comparison, when my system is closely balanced?
Since these inputs are verified at commissioning, maintenance verification requires ensuring
that phase quantities are as expected and that 3IO and 3VO quantities appear equal to or close
to 0.
These quantities also may be verified by use of oscillographic records for connected
microprocessor relays as recorded during system Disturbances. Such records may compare to
similar values recorded at other locations by other microprocessor relays for the same event, or
compared to expected values (from short circuit studies) for known Fault locations.
What does this Standard require for testing an auxiliary tripping relay?
Table 1 and Table 3 requires that a trip test must verify that the auxiliary tripping relay(s)
and/or lockout relay(s) which are directly in a trip path from the protective relay to the
interrupting device trip coil operate(s) electrically. Auxiliary outputs not in a trip path (i.e.
annunciation or DME input) are not required, by this standard, to be checked.
Do I have to perform a full end-to-end test of a Special Protection System?
No. All portions of the SPS need to be maintained, and the portions must overlap, but the
overall SPS does not need to have a single end‐to‐end test. In other words it may be tested in
piecemeal fashion provided all of the pieces are verified.
What about SPS interfaces between different entities or owners?
As in all of the Protection System requirements, SPS segments can be tested individually, thus
minimizing the need to accommodate complex maintenance schedules.
What do I have to do if I am using a phasor measurement unit (PMU) as part of a
Protection System or Special Protection System?
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Any Phasor Measurement Unit (PMU) function whose output is used in a Protection System or
Special Protection System (as opposed to a monitoring task) must be verified as a component in
a Protection System.
How do I maintain a Special Protection System or relay sensing for non-distributed
UFLS or UVLS Systems?
Since components of the SPS, UFLS and UVLS are the same types of components as those in
Protection Systems, then these components should be maintained like similar components
used for other Protection System functions. In many cases the devices for SPS, UFLS and UVLS
are also used for other protective functions. The same maintenance activities apply with the
exception that distributed systems (UFLS and UVLS) have fewer dc supply and control circuitry
maintenance activity requirements.
For the testing of the output action, verification may be by breaker tripping, but may be verified
in overlapping segments. For example, an SPS that trips a remote circuit breaker might be
tested by testing the various parts of the scheme in overlapping segments. Another method is
to document the Real‐time tripping of an SPS scheme should that occur. Forced trip tests of
circuit breakers (etc) that are a part of distributed UFLS or UVLS schemes are not required.
The established maximum allowable intervals do not align well with the scheduled
outages for my power plant. Can I extend the maintenance to the next scheduled
outage following the established maximum interval?
No. You must complete your maintenance within the established maximum allowable intervals
in order to be compliant. You will need to schedule your maintenance during available outages
to complete your maintenance as required, even if it means that you may do protective relay
maintenance more frequently than the maximum allowable intervals. The maintenance
intervals were selected with typical plant outages, among other things, in mind.
If I am unable to complete the maintenance, as required, due to a major natural
disaster (hurricane, earthquake, etc.), how will this affect my compliance with this
standard?
The Sanction Guidelines of the North American Electric Reliability Corporation, effective
January 15, 2008, provides that the Compliance Monitor will consider extenuating
circumstances when considering any sanctions.
What if my observed testing results show a high incidence of out-of-tolerance
relays; or, even worse, I am experiencing numerous relay Misoperations due to the
relays being out-of-tolerance?
The established maximum time intervals are mandatory only as a not‐to‐exceed limitation. The
establishment of a maximum is measurable. But any entity can choose to test some or all of
their Protection System components more frequently (or to express it differently, exceed the
minimum requirements of the standard). Particularly if you find that the maximum intervals in
the standard do not achieve your expected level of performance, it is understandable that you
would maintain the related equipment more frequently. A high incidence of relay
Misoperations is in no one’s best interest.
We believe that the four-month interval between inspections is unneccessary. Why
can we not perform these inspections twice per year?
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The Standard Drafting Team, through the comment process, has discovered that routine
monthly inspections are not the norm. To align routine station inspections with other
important inspections, the four‐month interval was chosen. In lieu of station visits, many
activities can be accomplished with automated monitoring and alarming.
Our maintenance plan calls for us to perform routine protective relay tests every 3
years. If we are unable to achieve this schedule, but we are able to complete the
procedures in less than the maximum time interval ,then are we in or out of
compliance?
According to R3, if you have a time‐based maintenance program, then you will be in violation of
the standard only if you exceed the maximum maintenance intervals prescribed in the Tables.
According to R4, if your device in question is part of a Performance‐Based Maintenance
program, then you will be in violation of the standard if you fail to meet your PSMP, even if you
do not exceed the maximum maintenance intervals prescribed in the Tables. The intervals in
the Tables are associated with TBM and CBM; Attachment A is associated with PBM.
Please provide a sample list of devices or systems that must be verified in a
generator, generator step-up transformer, generator connected station service or
generator connected excitation transformer to meet the requirements of this
maintenance standard.
Examples of typical devices and systems that may directly trip the generator, or trip through a
lockout relay, may include, but are not necessarily limited to:
Fault protective functions, including distance functions, voltage‐restrained overcurrent
functions, or voltage‐controlled overcurrent functions
Loss‐of‐field relays
Volts‐per‐hertz relays
Negative sequence overcurrent relays
Over voltage and under voltage protection relays
Stator‐ground relays
Communications‐based Protection Systems such as transfer‐trip systems
Generator differential relays
Reverse power relays
Frequency relays
Out‐of‐step relays
Inadvertent energization protection
Breaker failure protection
For generator step‐up, generator‐connected station service transformers, or generator
connected excitation transformers, operation of any of the following associated protective
relays frequently would result in a trip of the generating unit; and, as such, would be included
in the program:
Transformer differential relays
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Neutral overcurrent relay
Phase overcurrent relays
Relays which trip breakers serving station auxiliary Loads such as pumps, fans, or fuel handling
equipment, etc., need not be included in the program, even if the loss of the those Loads could
result in a trip of the generating unit. Furthermore, relays which provide protection to
secondary unit substation (SUS) or low switchgear transformers and relays protecting other
downstream plant electrical distribution system components are not included in the scope of
this program, even if a trip of these devices might eventually result in a trip of the generating
unit. For example, a thermal overcurrent trip on the motor of a coal‐conveyor belt could
eventually lead to the tripping of the generator, but it does not cause the trip.
In the case where a plant does not have a generator connected station service
transformer such that it is normally fed from a system connected station service
transformer, is it still the drafting team’s intent to exclude the Protection Systems
for these system connected auxiliary transformers from scope even when the loss
of the normal (system connected) station service transformer will result in a trip of
a BES generating Facility?
The SDT does not intend that the system‐connected station service transformers be included in
the Applicability. The generator‐connected station service transformers and generator
connected excitation transformers are often connected to the generator bus directly without
an interposing breaker; thus, the Protection Systems on these transformers will trip the
generator as discussed in 4.2.5.1.
What is meant by “verify operation of the relay inputs and outputs that are essential
to proper functioning of the Protection System?”
Any input or output (of the relay) that “affects the tripping” of the breaker is included in the
scope of I/O of the relay to be verified. By “affects the tripping,” one needs to realize that
sometimes there are more inputs and outputs than simply the output to the trip coil. Many
important protective functions include things like breaker fail initiation, zone timer initiation
and sometimes even 52a/b contact inputs are needed for a protective relay to correctly
operate.
Each input should be “picked up” or “turned on and off” and verified as changing state by the
microprocessor of the relay. Each output should be “operated” or “closed and opened” from
the microprocessor of the relay and the output should be verified to change state on the output
terminals of the relay. One possible method of testing inputs of these relays is to “jumper” the
needed dc voltage to the input and verify that the relay registered the change of state.
Electromechanical lock‐out relays (86) (used to convey the tripping current to the trip coils)
need to be electrically operated to prove the capability of the device to change state. These
tests need to be accomplished at least every six years, unless PBM methodology is applied.
The contacts on the 86 or auxiliary tripping relays (94) that change state to pass on the trip
current to a breaker trip coil need only be checked every 12 years with the control circuitry.
What is the difference between a distributed UFLS/UVLS and a non-distributed
UFLS/UVLS scheme?
A distributed UFLS or UVLS scheme contains individual relays which make independent Load
shed decisions based on applied settings and localized voltage and/or current inputs. A
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
38
distributed scheme may involve an enable/disable contact in the scheme and still be considered
a distributed scheme. A non‐distributed UFLS or UVLS scheme involves a system where there is
some type of centralized measurement and Load shed decision being made. A non‐distributed
UFLS/UVLS scheme is considered similar to an SPS scheme and falls under Table 1 for
maintenance activities and intervals.
8.2 Retention of Records
PRC‐005‐1 describes a reporting or auditing cycle of one year and retention of records for three
years. However, with a three‐year retention cycle, the records of verification for a Protection
System might be discarded before the next verification, leaving no record of what was done if a
Misoperation or failure is to be analyzed.
PRC‐005‐3 corrects this by requiring:
The Transmission Owner, Generator Owner, and Distribution Provider shall each retain
documentation of the two most recent performances of each distinct maintenance activity for
the Protection System components, or to the previous scheduled (on‐site) audit date, whichever
is longer.
This requirement assures that the documentation shows that the interval between
maintenance cycles correctly meets the maintenance interval limits. The requirement is
actually alerting the industry to documentation requirements already implemented by audit
teams. Evidence of compliance bookending the interval shows interval accomplished instead of
proving only your planned interval.
The SDT is aware that, in some cases, the retention period could be relatively long. But, the
retention of documents simply helps to demonstrate compliance.
8.2.1 Frequently Asked Questions:
Please use a specific example to demonstrate the data retention requirements.
The data retention requirements are intended to allow the availability of maintenance records
to demonstrate that the time intervals in your maintenance plan were upheld. For example:
“Company A” has a maintenance plan that requires its electromechanical protective relays be
tested every three calendar years, with a maximum allowed grace period of an additional 18
months. This entity would be required to maintain its records of maintenance of its last two
routine scheduled tests. Thus, its test records would have a latest routine test, as well as its
previous routine test. The interval between tests is, therefore, provable to an auditor as being
within “Company A’s” stated maximum time interval of 4.5 years.
The intent is not to require three test results proving two time intervals, but rather have two
test results proving the last interval. The drafting team contends that this minimizes storage
requirements, while still having minimum data available to demonstrate compliance with time
intervals.
If an entity prefers to utilize Performance‐Based Maintenance, then statistical data may well be
retained for extended periods to assist with future adjustments in time intervals.
If an equipment item is replaced, then the entity can restart the maintenance‐time‐interval‐
clock if desired; however, the replacement of equipment does not remove any documentation
requirements that would have been required to verify compliance with time‐interval
requirements. In other words, do not discard maintenance data that goes to verify your work.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
39
The retention of documentation for new and/or replaced equipment is all about proving that
the maintenance intervals had been in compliance. For example, a long‐range plan of upgrades
might lead an entity to ignore required maintenance; retaining the evidence of prior
maintenance that existed before any retirements and upgrades proves compliance with the
standard.
What does this Maintenance Standard say about commissioning? Is it necessary to
have documentation in your maintenance history of the completion of commission
testing?
This standard does not establish requirements for commission testing. Commission testing
includes all testing activities necessary to conclude that a Facility has been built in accordance
with design. While a thorough commission testing program would include, either directly or
indirectly, the verification of all those Protection System attributes addressed by the
maintenance activities specified in the Tables of PRC‐005‐3, verification of the adequacy of
initial installation necessitates the performance of testing and inspections that go well beyond
these routine maintenance activities. For example, commission testing might set baselines for
future tests; perform acceptance tests and/or warranty tests; utilize testing methods that are
not generally done routinely like staged‐Fault‐tests.
However, many of the Protection System attributes which are verified during commission
testing are not subject to age related or service related degradation, and need not be re‐
verified within an ongoing maintenance program. Example – it is not necessary to re‐verify
correct terminal strip wiring on an ongoing basis.
PRC‐005‐3 assumes that thorough commission testing was performed prior to a Protection
System being placed in service. PRC‐005‐3 requires performance of maintenance activities that
are deemed necessary to detect and correct plausible age and service related degradation of
components, such that a properly built and commission tested Protection System will continue
to function as designed over its service life.
It should be noted that commission testing frequently is performed by a different organization
than that which is responsible for the ongoing maintenance of the Protection System.
Furthermore, the commission testing activities will not necessarily correlate directly with the
maintenance activities required by the standard. As such, it is very likely that commission
testing records will deviate significantly from maintenance records in both form and content;
and, therefore, it is not necessary to maintain commission testing records within the
maintenance program documentation.
Notwithstanding the differences in records, an entity would be wise to retain commissioning
records to show a maintenance start date. (See below). An entity that requires that their
commissioning tests have, at a minimum, the requirements of PRC‐005‐3 would help that entity
prove time interval maximums by setting the initial time clock.
How do you determine the initial due date for maintenance?
The initial due date for maintenance should be based upon when a Protection System was
tested. Alternatively, an entity may choose to use the date of completion of the commission
testing of the Protection System component and the system was placed into service as the
starting point in determining its first maintenance due dates. Whichever method is chosen, for
newly installed Protection Systems the components should not be placed into service until
minimum maintenance activities have taken place.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
40
It is conceivable that there can be a (substantial) difference in time between the date of testing,
as compared to the date placed into service. The use of the “Calendar Year” language can help
determine the next due date without too much concern about being non‐compliant for missing
test dates by a small amount (provided your dates are not already at the end of a year).
However, if there is a substantial amount of time difference between testing and in‐service
dates, then the testing date should be followed because it is the degradation of components
that is the concern. While accuracy fluctuations may decrease when components are not
energized, there are cases when degradation can take place, even though the device is not
energized. Minimizing the time between commissioning tests and in‐service dates will help.
If I miss two battery inspections four times out of 100 Protection System
components on my transmission system, does that count as 2% or 8% when
counting Violation Severity Level (VSL) for R3?
The entity failed to complete its scheduled program on two of its 100 Protection System
components, which would equate to 2% for application to the VSL Table for Requirement R3.
This VSL is written to compare missed components to total components. In this case two
components out of 100 were missed, or 2%.
How do I achieve a “grace period” without being out of compliance?
The objective here is to create a time extension within your own PSMP that still does not
violate the maximum time intervals stated in the standard. Remember that the maximum time
intervals listed in the Tables cannot be extended.
For the purposes of this example, concentrating on just unmonitored protective relays – Table
1‐1 specifies a maximum time interval (between the mandated maintenance activities) of six
calendar years. Your plan must ensure that your unmonitored relays are tested at least once
every six calendar years. You could, within your PSMP, require that your unmonitored relays be
tested every four calendar years, with a maximum allowable time extension of 18 calendar
months. This allows an entity to have deadlines set for the auto‐generation of work orders, but
still has the flexibility in scheduling complex work schedules. This also allows for that 18
calendar months to act as a buffer, in effect a grace period within your PSMP, in the event of
unforeseen events. You will note that this example of a maintenance plan interval has a
planned time of four years; it also has a built‐in time extension allowed within the PSMP, and
yet does not exceed the maximum time interval allowed by the standard. So while there are no
time extensions allowed beyond the standard, an entity can still have substantial flexibility to
maintain their Protection System components.
8.3 Basis for Table 1 Intervals
When developing the original Protection System Maintenance – A Technical Reference in 2007,
the SPCTF collected all available data from Regional Entities (REs) on time intervals
recommended for maintenance and test programs. The recommendations vary widely in
categorization of relays, defined maintenance actions, and time intervals, precluding
development of intervals by averaging. The SPCTF also reviewed the 2005 Report [2] of the
IEEE Power System Relaying Committee Working Group I‐17 (Transmission Relay System
Performance Comparison). Review of the I‐17 report shows data from a small number of
utilities, with no company identification or means of investigating the significance of particular
results.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
41
To develop a solid current base of practice, the SPCTF surveyed its members regarding their
maintenance intervals for electromechanical and microprocessor relays, and asked the
members to also provide definitively‐known data for other entities. The survey represented 470
GW of peak Load, or 4% of the NERC peak Load. Maintenance interval averages were compiled
by weighting reported intervals according to the size (based on peak Load) of the reporting
utility. Thus, the averages more accurately represent practices for the large populations of
Protection Systems used across the NERC regions.
The results of this survey with weighted averaging indicate maintenance intervals of five years
for electromechanical or solid state relays, and seven years for unmonitored microprocessor
relays.
A number of utilities have extended maintenance intervals for microprocessor relays beyond
seven years, based on favorable experience with the particular products they have installed. To
provide a technical basis for such extension, the SPCTF authors developed a recommendation
of 10 years using the Markov modeling approach from [1], as summarized in Section 8.4. The
results of this modeling depend on the completeness of self‐testing or monitoring. Accordingly,
this extended interval is allowed by Table 1, only when such relays are monitored as specified in
the attributes of monitoring contained in Tables 1‐1 through 1‐5 and Table 2. Monitoring is
capable of reporting Protection System health issues that are likely to affect performance
within the 10 year time interval between verifications.
It is important to note that, according to modeling results, Protection System availability barely
changes as the maintenance interval is varied below the 10‐year mark. Thus, reducing the
maintenance interval does not improve Protection System availability. With the assumptions of
the model regarding how maintenance is carried out, reducing the maintenance interval
actually degrades Protection System availability.
8.4 Basis for Extended Maintenance Intervals for Microprocessor Relays
Table 1 allows maximum verification intervals that are extended based on monitoring level.
The industry has experience with self‐monitoring microprocessor relays that leads to the Table
1 value for a monitored relay, as explained in Section 8.3. To develop a basis for the maximum
interval for monitored relays in their Protection System Maintenance – A Technical Reference,
the SPCTF used the methodology of Reference [1], which specifically addresses optimum
routine maintenance intervals. The Markov modeling approach of [1] is judged to be valid for
the design and typical failure modes of microprocessor relays.
The SPCTF authors ran test cases of the Markov model to calculate two key probability
measures:
Relay Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity while the power system Element to be protected is in service.
Abnormal Unavailability ‐ the probability that the relay is out of service due to failure or
maintenance activity when a Fault occurs, leading to failure to operate for the Fault.
The parameter in the Markov model that defines self‐monitoring capability is ST (for self test).
ST = 0 if there is no self‐monitoring; ST = 1 for full monitoring. Practical ST values are estimated
to range from .75 to .95. The SPCTF simulation runs used constants in the Markov model that
were the same as those used in [1] with the following exceptions:
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Sn, Normal tripping operations per hour = 21600 (reciprocal of normal Fault clearing time of 10
cycles)
Sb, Backup tripping operations per hour = 4320 (reciprocal of backup Fault clearing time of 50
cycles)
Rc, Protected component repairs per hour = 0.125 (8 hours to restore the power system)
Rt, Relay routine tests per hour = 0.125 (8 hours to test a Protection System)
Rr, Relay repairs per hour = 0.08333 (12 hours to complete a Protection System repair after
failure)
Experimental runs of the model showed low sensitivity of optimum maintenance interval to
these parameter adjustments.
The resulting curves for relay unavailability and abnormal unavailability versus maintenance
interval showed a broad minimum (optimum maintenance interval) in the vicinity of 10 years –
the curve is flat, with no significant change in either unavailability value over the range of 9, 10,
or 11 years. This was true even for a relay mean time between Failures (MTBF) of 50 years,
much lower than MTBF values typically published for these relays. Also, the Markov modeling
indicates that both the relay unavailability and abnormal unavailability actually become higher
with more frequent testing. This shows that the time spent on these more frequent tests yields
no failure discoveries that approach the negative impact of removing the relays from service
and running the tests.
The PSMT SDT discussed the practical need for “time‐interval extensions” or “grace periods” to
allow for scheduling problems that resulted from any number of business contingencies. The
time interval discussions also focused on the need to reflect industry norms surrounding
Generator outage frequencies. Finally, it was again noted that FERC Order 693 demanded
maximum time intervals. “Maximum time intervals” by their very term negates any “time‐
interval extension” or “grace periods.” To recognize the need to follow industry norms on
Generator outage frequencies and accommodate a form of time‐interval extension, while still
following FERC Order 693, the Standard Drafting Team arrived at a six‐year interval for the
electromechanical relay, instead of the five‐year interval arrived at by the SPCTF. The PSMT
SDT has followed the FERC directive for a maximum time interval and has determined that no
extensions will be allowed. Six years has been set for the maximum time interval between
manual maintenance activities. This maximum time interval also works well for maintenance
cycles that have been in use in generator plants for decades.
For monitored relays, the PSMT SDT notes that the SPCTF called for 10 years as the interval
between maintenance activities. This 10‐year interval was chosen, even though there was
“…no significant change in unavailability value over the range of 9, 10, or 11 years. This was
true even for a relay Mean Time between Failures (MTBF) of 50 years…” The Standard Drafting
Team again sought to align maintenance activities with known successful practices and outage
schedules. The Standard does not allow extensions on any component of the Protection
System; thus, the maximum allowed interval for these components has been set to 12 years.
Twelve years also fits well into the traditional maintenance cycles of both substations and
generator plants.
Also of note is the Table’s use of the term “Calendar” in the column for “Maximum
Maintenance Interval.” The PSMT SDT deemed it necessary to include the term “Calendar” to
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43
facilitate annual maintenance planning, scheduling and implementation. This need is the result
of known occurrences of system requirements that could cause maintenance schedules to be
missed by a few days or weeks. The PSMT SDT chose the term “Calendar” to preclude the need
to have schedules be met to the day. An electromechanical protective relay that is maintained
in year number one need not be revisited until six years later (year number seven). For
example, a relay was maintained April 10, 2008; maintenance would need to be completed no
later than December 31, 2014.
Though not a requirement of this standard, to stay in line with many Compliance Enforcement
Agencies audit processes an entity should define, within their own PSMP, the entity’s use of
terms like annual, calendar year, etc. Then, once this is within the PSMP, the entity should
abide by their chosen language.
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9. Performance-Based Maintenance Process
In lieu of using the Table 1 intervals, a Performance‐Based Maintenance process may be used to
establish maintenance intervals (PRC‐005 Attachment A Criteria for a Performance‐Based
Protection System Maintenance Program). A Performance‐Based Maintenance process may
justify longer maintenance intervals, or require shorter intervals relative to Table 1. In order to
use a Performance‐Based Maintenance process, the documented maintenance program must
include records of repairs, adjustments, and corrections to covered Protection Systems in order
to provide historical justification for intervals, other than those established in Table 1.
Furthermore, the asset owner must regularly analyze these records of corrective actions to
develop a ranking of causes. Recurrent problems are to be highlighted, and remedial action
plans are to be documented to mitigate or eliminate recurrent problems.
Entities with Performance‐Based Maintenance track performance of Protection Systems,
demonstrate how they analyze findings of performance failures and aberrations, and
implement continuous improvement actions. Since no maintenance program can ever
guarantee that no malfunction can possibly occur, documentation of a Performance‐Based
Maintenance program would serve the utility well in explaining to regulators and the public a
Misoperation leading to a major System outage event.
A Performance‐Based Maintenance program requires auditing processes like those included in
widely used industrial quality systems (such as ISO 9001‐2000, Quality Management Systems
— Requirements; or applicable parts of the NIST Baldridge National Quality Program). The
audits periodically evaluate:
• The completeness of the documented maintenance process
• Organizational knowledge of and adherence to the process
• Performance metrics and documentation of results
• Remediation of issues
• Demonstration of continuous improvement.
In order to opt into a Performance‐Based Maintenance (PBM) program, the asset owner must
first sort the various Components into population segments. Any population segment must be
comprised of at least 60 individual units; if any asset owner opts for PBM, but does not own 60
units to comprise a population, then that asset owner may combine data from other asset
owners until the needed 60 units is aggregated. Each population segment must be composed
of a grouping of Components of a consistent design standard or particular model or type from a
single manufacturer and subjected to similar environmental factors. For example: One
segment cannot be comprised of both GE & Westinghouse electro‐mechanical lock‐out relays;
likewise, one segment cannot be comprised of 60 GE lock‐out relays, 30 of which are in a dirty
environment, and the remaining 30 from a clean environment. This PBM process cannot be
applied to batteries, but can be applied to all other Components, including (but not limited to)
specific battery chargers, instrument transformers, trip coils and/or control circuitry (etc.).
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
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9.1 Minimum Sample Size
Large Sample Size
An assumption that needs to be made when choosing a sample size is “the sampling
distribution of the sample mean can be approximated by a normal probability distribution.”
The Central Limit Theorem states: “In selecting simple random samples of size n from a
population, the sampling distribution of the sample mean x can be approximated by a normal
probability distribution as the sample size becomes large.” (Essentials of Statistics for Business
and Economics, Anderson, Sweeney, Williams, 2003.)
To use the Central Limit Theorem in statistics, the population size should be large. The
references below are supplied to help define what is large.
“… whenever we are using a large simple random sample (rule of thumb: n>=30),
the central limit theorem enables us to conclude that the sampling distribution
of the sample mean can be approximated by a normal distribution.” (Essentials
of Statistics for Business and Economics, Anderson, Sweeney, Williams, 2003.)
“If samples of size n, when n>=30, are drawn from any population with a mean u
and a standard deviation , the sampling distribution of sample means
approximates a normal distribution. The greater the sample size, the better the
approximation.” (Elementary Statistics ‐ Picturing the World, Larson, Farber,
2003.)
“The sample size is large (generally n>=30)… (Introduction to Statistics and Data
Analysis ‐ Second Edition, Peck, Olson, Devore, 2005.)
“… the normal is often used as an approximation to the t distribution in a test of
a null hypothesis about the mean of a normally distributed population when the
population variance is estimated from a relatively large sample. A sample size
exceeding 30 is often given as a minimal size in this connection.” (Statistical
Analysis for Business Decisions, Peters, Summers, 1968.)
Error of Distribution Formula
Beyond the large sample size discussion above, a sample size requirement can be estimated
using the bound on the Error of Distribution Formula when the expected result is of a
“Pass/Fail” format and will be between 0 and 1.0.
The Error of Distribution Formula is:
z
1
n
Where:
= bound on the error of distribution (allowable error)
z = standard error
= expected failure rate
n = sample size required
Solving for n provides:
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46
2
z
n 1
Minimum Population Size to use Performance-Based Program
One entity’s population of components should be large enough to represent a sizeable sample
of a vendor’s overall population of manufactured devices. For this reason, the following
assumptions are made:
B = 5%
z = 1.96 (This equates to a 95% confidence level)
= 4%
Using the equation above, n=59.0.
Minimum Sample Size to evaluate Performance-Based Program
The number of components that should be included in a sample size for evaluation of the
appropriate testing interval can be smaller because a lower confidence level is acceptable since
the sample testing is repeated or updated annually. For this reason, the following assumptions
are made:
B = 5%
z = 1.44 (85% confidence level)
= 4%
Using the equation above, n=31.8.
Recommendation
Based on the above discussion, a sample size should be at least 30 to allow use of the equation
mentioned. Using this and the results of the equation, the following numbers are
recommended (and required within the standard):
Minimum Population Size to use Performance‐Based Maintenance Program = 60
Minimum Sample Size to evaluate Performance‐Based Program = 30.
Once the population segment is defined, then maintenance must begin within the intervals as
outlined for the device described in the Tables 1‐1 through 1‐5. Time intervals can be
lengthened provided the last year’s worth of components tested (or the last 30 units
maintained, whichever is more) had fewer than 4% Countable Events. It is notable that 4% is
specifically chosen because an entity with a small population (30 units) would have to adjust its
time intervals between maintenance if more than one Countable Event was found to have
occurred during the last analysis period. A smaller percentage would require that entity to
adjust the time interval between maintenance activities if even one unit is found out of
tolerance or causes a Misoperation.
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The minimum number of units that can be tested in any given year is 5% of the population.
Note that this 5% threshold sets a practical limitation on total length of time between intervals
at 20 years.
If at any time the number of Countable Events equals or exceeds 4% of the last year’s tested
components (or the last 30 units maintained, whichever is more), then the time period
between manual maintenance activities must be decreased. There is a time limit on reaching
the decreased time at which the Countable Events is less than 4%; this must be attained within
three years.
Performance-Based Program Evaluation Example
The 4% performance target was derived as a protection system performance target and was
selected based on the drafting team’s experience and studies performed by several utilities.
This is not derived from the performance of discrete devices. Microprocessor relays and
electromechanical relays have different performance levels. It is not appropriate to compare
these performance levels to each other. The performance of the segment should be compared
to the 4% performance criteria.
In consideration of the use of Performance Based Maintenance (PBM), the user should consider
the effects of extended testing intervals and the established 4% failure rate. In the table shown
below, the segment is 1000 units. As the testing interval (in years) increases, the number of
units tested each year decreases. The number of countable events allowed is 4% of the tested
units. Countable events are the failure of a Component requiring repair or replacement, any
corrective actions performed during the maintenance test on the units within the testing
segment (units per year), or any misoperation attributable to hardware failure or calibration
failure found within the entire segment (1000 units) during the testing year.
Example: 1000 units in the segment with a testing interval of 8 years: The number of units
tested each year will be 125 units. The total allowable countable events equals: 125 X .04 = 5.
This number includes failure of a Component requiring repair or replacement, corrective issues
found during testing, and the total number of misoperations (attributable to hardware or
calibration failure within the testing year) associated with the entire segment of 1000 units.
Example: 1000 units in the segment with a testing interval of 16 years: The number of units
tested each year will be 63 units. The total allowable countable events equals: 63 X .04 = 2.5.
As shown in the above examples, doubling the testing interval reduces the number of
allowable events by half.
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Total number of units in the segment
Failure rate
Testing
Intervals
(Years)
1
2
4
6
8
10
12
14
16
18
20
Units
Per
Year
1000.00
500.00
250.00
166.67
125.00
100.00
83.33
71.43
62.50
55.56
50.00
Formatted Table
1000
4.00%
Acceptable Number of
Countable Events per year
40.00
20.00
10.00
6.67
5.00
4.00
3.33
2.86
2.50
2.22
2.00
Yearly Failure Rate
Based on 1000
Units in Segment
4.00%
2.00%
1.00%
0.67%
0.50%
0.40%
0.33%
0.29%
0.25%
0.22%
0.20%
Using the prior year’s data, determine the maximum allowable maintenance interval for each
Segment such that the Segment experiences Countable Events on no more than 4% of the
Components within the Segment, for the greater of either the last 30 Components maintained
or all Components maintained in the previous year.
Segment – Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a Segment. A Segment must contain at least sixty (60)
individual Components.
Countable Event – A failure of a Component requiring repair or replacement, any condition
discovered during the maintenance activities in Tables 1‐1 through 1‐5, Table 3, and Table 4
which requires corrective action or a Protection System Misoperation attributed to hardware
failure or calibration failure. Misoperations due to product design errors, software errors, relay
settings different from specified settings, Protection System Component or Automatic Reclosing
configuration or application errors are not included in Countable Events.
9.2 Frequently Asked Questions:
I’m a small entity and cannot aggregate a population of Protection System
components to establish a segment required for a Performance-Based Protection
System Maintenance Program. How can I utilize that opportunity?
Multiple asset owning entities may aggregate their individually owned populations of individual
Protection System components to create a segment that crosses ownership boundaries. All
entities participating in a joint program should have a single documented joint management
process, with consistent Protection System Maintenance Programs (practices, maintenance
intervals and criteria), for which the multiple owners are individually responsible with respect
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
49
to the requirements of the Standard. The requirements established for Performance‐Based
Maintenance must be met for the overall aggregated program on an ongoing basis.
The aggregated population should reflect all factors that affect consistent performance across
the population, including any relevant environmental factors such as geography, power‐plant
vs. substation, and weather conditions.
Can an owner go straight to a Performance-Based Maintenance program schedule, if
they have previously gathered records?
Yes. An owner can go to a Performance‐Based Maintenance program immediately. The owner
will need to comply with the requirements of a Performance‐Based Maintenance program as
listed in the Standard. Gaps in the data collected will not be allowed; therefore, if an owner
finds that a gap exists such that they cannot prove that they have collected the data as required
for a Performance‐Based Maintenance program then they will need to wait until they can prove
compliance.
When establishing a Performance-Based Maintenance program, can I use test data
from the device manufacturer, or industry survey results, as results to help establish
a basis for my Performance-Based intervals?
No, you must use actual in‐service test data for the components in the segment.
What types of Misoperations or events are not considered Countable Events in the
Performance-Based Protection System Maintenance (PBM) Program?
Countable Events are intended to address conditions that are attributed to hardware failure or
calibration failure; that is, conditions that reflect deteriorating performance of the component.
These conditions include any condition where the device previously worked properly, then, due
to changes within the device, malfunctioned or degraded to the point that re‐calibration (to
within the entity’s tolerance ) was required.
For this purpose of tracking hardware issues, human errors resulting in Protection System
Misoperations during system installation or maintenance activities are not considered
Countable Events. Examples of excluded human errors include relay setting errors, design
errors, wiring errors, inadvertent tripping of devices during testing or installation, and
misapplication of Protection System components. Examples of misapplication of Protection
System components include wrong CT or PT tap position, protective relay function
misapplication, and components not specified correctly for their installation. Obviously, if one is
setting up relevant data about hardware failures then human failures should be eliminated
from the hardware performance analysis.
One example of human‐error is not pertinent data might be in the area of testing “86” lock‐out
relays (LOR). “Entity A” has two types of LOR’s type “X” and type “Y”; they want to move into a
performance based maintenance interval. They have 1000 of each type, so the population
variables are met. During electrical trip testing of all of their various schemes over the initial six‐
year interval they find zero type “X” failures, but human error led to tripping a BES Element 100
times; they find 100 type “Y” failures and had an additional 100 human‐error caused tripping
incidents. In this example the human‐error caused Misoperations should not be used to judge
the performance of either type of LOR. Analysis of the data might lead “Entity A” to change
time intervals. Type “X” LOR can be placed into extended time interval testing because of its
low failure rate (zero failures) while Type “Y” would have to be tested more often than every 6
calendar years (100 failures divided by 1000 units exceeds the 4% tolerance level).
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
50
Certain types of Protection System component errors that cause Misoperations are not
considered Countable Events. Examples of excluded component errors include device
malfunctions that are correctable by firmware upgrades and design errors that do not impact
protection function.
What are some examples of methods of correcting segment perfomance for
Performance-Based Maintenance?
There are a number of methods that may be useful for correcting segment performance for
mal‐performing segments in a Performance‐Based Maintenance system. Some examples are
listed below.
The maximum allowable interval, as established by the Performance‐Based
Maintenance system, can be decreased. This may, however, be slow to correct the
performance of the segment.
Identifiable sub‐groups of components within the established segment, which have
been identified to be the mal‐performing portion of the segment, can be broken out as
an independent segment for target action. Each resulting segment must satisfy the
minimum population requirements for a Performance‐Based Maintenance program in
order to remain within the program.
Targeted corrective actions can be taken to correct frequently occurring problems. An
example would be replacement of capacitors within electromechanical distance relays if
bad capacitors were determined to be the cause of the mal‐performance.
components within the mal‐performing segment can be replaced with other
components (electromechanical distance relays with microprocessor relays, for
example) to remove the mal‐performing segment.
If I find (and correct) a Unresolved Maintenance Issue as a result of a Misoperation
investigation (Re: PRC-004), how does this affect my Performance-Based
Maintenance program?
If you perform maintenance on a Protection System component for any reason (including as
part of a PRC‐004 required Misoperation investigation/corrective action), the actions
performed can count as a maintenance activity provided the activities in the relevant Tables
have been done, and, if you desire, “reset the clock” on everything you’ve done. In a
Performance‐Based Maintenance program, you also need to record the Unresolved
Maintenance Issue as a Countable Event within the relevant component group segment and
use it in the analysis to determine your correct Performance‐Based Maintenance interval for
that component group. Note that “resetting the clock” should not be construed as interfering
with an entity’s routine testing schedule because the “clock‐reset” would actually make for a
decreased time interval by the time the next routine test schedule comes around.
For example a relay scheme, consisting of four relays, is tested on 1‐1‐11 and the PSMP has a
time interval of 3 calendar years with an allowable extension of 1 calendar year. The relay
would be due again for routine testing before the end of the year 2015. This mythical relay
scheme has a Misoperation on 6‐1‐12 that points to one of the four relays as bad. Investigation
proves a bad relay and a new one is tested and installed in place of the original. This
replacement relay actually could be retested before the end of the year 2016 (clock‐reset) and
not be out of compliance. This requires tracking maintenance by individual relays and is
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
51
allowed. However, many companies schedule maintenance in other ways like by substation or
by circuit breaker or by relay scheme. By these methods of tracking maintenance that “replaced
relay” will be retested before the end of the year 2015. This is also acceptable. In no case was a
particular relay tested beyond the PSMP of four years max, nor was the 6 year max of the
Standard exceeded. The entity can reset the clock if they desire or the entity can continue with
original schedules and, in effect, test even more frequently.
Why are batteries excluded from PBM? What about exclusion of batteries from
condition based maintenance?
Batteries are the only element of a Protection System that is a perishable item with a shelf life.
As a perishable item batteries require not only a constant float charge to maintain their
freshness (charge), but periodic inspection to determine if there are problems associated with
their aging process and testing to see if they are maintaining a charge or can still deliver their
rated output as required.
Besides being perishable, a second unique feature of a battery that is unlike any other
Protection System element is that a battery uses chemicals, metal alloys, plastics, welds, and
bonds that must interact with each other to produce the constant dc source required for
Protection Systems, undisturbed by ac system Disturbances.
No type of battery manufactured today for Protection System application is free from problems
that can only be detected over time by inspection and test. These problems can arise from
variances in the manufacturing process, chemicals and alloys used in the construction of the
individual cells, quality of welds and bonds to connect the components, the plastics used to
make batteries and the cell forming process for the individual battery cells.
Other problems that require periodic inspection and testing can result from transportation
from the factory to the job site, length of time before a charge is put on the battery, the
method of installation, the voltage level and duration of equalize charges, the float voltage level
used, and the environment that the battery is installed in.
All of the above mentioned factors and several more not discussed here are beyond the control
of the Functional Entities that want to use a Performance‐Based Protection System
Maintenance (PBM) program. These inherent variances in the aging process of a battery cell
make establishment of a designated segment based on manufacturer and type of battery
impossible.
The whole point of PBM is that if all variables are isolated then common aging and performance
criteria would be the same. However, there are too many variables in the electrochemical
process to completely isolate all of the performance‐changing criteria.
Similarly, Functional Entities that want to establish a condition‐based maintenance program
using the highest levels of monitoring, resulting in the least amount of hands‐on maintenance
activity, cannot completely eliminate some periodic maintenance of the battery used in a
station dc supply. Inspection of the battery is required on a Maximum Maintenance Interval
listed in the tables due to the aging processes of station batteries. However, higher degrees of
monitoring of a battery can eliminate the requirement for some periodic testing and some
inspections (see Table 1‐4).
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
52
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM.
Entity has 1000 GE‐HEA lock‐out relays; this is greater than the minimum sample requirement
of 60. They start out testing all of the relays within the prescribed Table requirements (6 year
max) by testing the relays every 5 years. The entity’s plan is to test 200 units per year; this is
greater than the minimum sample size requirement of 30. For the sake of example only the
following will show 6 failures per year, reality may well have different numbers of failures every
year. PBM requires annual assessment of failures found per units tested. After the first year of
tests the entity finds 6 failures in the 200 units tested. 6/200= 3% failure rate. This entity is now
allowed to extend the maintenance interval if they choose. The entity chooses to extend the
maintenance interval of this population segment out to 10 years. This represents a rate of 100
units tested per year; entity selects 100 units to be tested in the following year. After that year
of testing these 100 units the entity again finds 6 failed units. 6/100= 6% failures. This entity
has now exceeded the acceptable failure rate for these devices and must accelerate testing of
all of the units at a higher rate such that the failure rate is found to be less than 4% per year;
the entity has three years to get this failure rate down to 4% or less (per year). In response to
the 6% failure rate, the entity decreases the testing interval to 8 years. This means that they will
now test 125 units per year (1000/8). The entity has just two years left to get the test rate
corrected.
After a year, they again find six failures out of the 125 units tested. 6/125= 5% failures. In
response to the 5% failure rate, the entity decreases the testing interval to seven years. This
means that they will now test 143 units per year (1000/7). The entity has just one year left to
get the test rate corrected. After a year, they again find six failures out of the 143 units tested.
6/143= 4.2% failures.
(Note that the entity has tried five years and they were under the 4% limit and they tried seven
years and they were over the 4% limit. They must be back at 4% failures or less in the next year
so they might simply elect to go back to five years.)
Instead, in response to the 5% failure rate, the entity decreases the testing interval to six years.
This means that they will now test 167 units per year (1000/6). After a year, they again find six
failures out of the 167 units tested. 6/167= 3.6% failures. Entity found that they could
maintain the failure rate at no more than 4% failures by maintaining the testing interval at six
years or less. Entity chose six‐year interval and effectively extended their TBM (five years)
program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20 year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
53
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
5 yrs
200
6
3%
Yes
10 yrs
2
1000
10 yrs
100
6
6%
Yes
8 yrs
3
1000
8 yrs
125
6
5%
Yes
7 yrs
4
1000
7 yrs
143
6
4.2%
Yes
6 yrs
5
1000
6 yrs
167
6
3.6%
No
6 yrs
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
54
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for control circuitry.
Note that the following example captures “Control Circuitry” as all of the trip paths associated
with a particular trip coil of a circuit breaker. An entity is not restricted to this method of
counting control circuits. Perhaps another method an entity would prefer would be to simply
track every individual (parallel) trip path. Or perhaps another method would be to track all of
the trip outputs from a specific (set) of relays protecting a specific element. Under the included
definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 1,000 circuit breakers, all of which have two trip coils, for a total of 2,000 trip coils; if
all circuitry was designed and built with a consistent (internal entity) standard, then this is
greater than the minimum sample requirement of 60.
For the sake of further example, the following facts are given:
Half of all relay panels (500) were built 40 years ago by an outside contractor, consisted of
asbestos wrapped 600V‐insulation panel wiring, and the cables exiting the control house are
THHN pulled in conduit direct to exactly half of all of the various circuit breakers. All of the
relay panels and cable pulls were built with consistent standards and consistent performance
standard expectations within the segment (which is greater than 60). Each relay panel has
redundant microprocessor (MPC) relays (retrofitted); each MPC relay supplies an individual trip
output to each of the two trip coils of the assigned circuit breaker.
Approximately 35 years ago, the entity developed their own internal construction crew and
now builds all of their own relay panels from parts supplied from vendors that meet the entity’s
specifications, including SIS 600V insulation wiring and copper‐sheathed cabling within the
direct conduits to circuit breakers. The construction crew uses consistent standards in the
construction. This newer segment of their control circuitry population is different than the
original segment, consistent (standards, construction and performance expectations) within the
new segment and constitutes the remainder of the entity’s population (another 500 panels and
the cabling to the remaining 500 circuit breakers). Each relay panel has redundant
microprocessor (MPC) relays; each MPC relay supplies an individual trip output to each of the
two trip coils of the assigned circuit breaker. Every trip path in this newer segment has a device
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
55
that monitors the voltage directly across the trip contacts of the MPC relays and alarms via RTU
and SCADA to the operations control room. This monitoring device, when not in alarm,
demonstrates continuity all the way through the trip coil, cabling and wiring back to the trip
contacts of the MPC relay.
The entity is tracking 2,000 trip coils (each consisting of multiple trip paths) in each of these two
segments. But half of all of the trip paths are monitored; therefore, the trip paths are
continuously tested and the circuit will alarm when there is a failure. These alarms have to be
verified every 12 years for correct operation.
The entity now has 1,000 trip coils (and associated trip paths) remaining that they have elected
to count as control circuits. The entity has instituted a process that requires the verification of
every trip path to each trip coil (one unit), including the electrical activation of the trip coil.
(The entity notes that the trip coils will have to be tripped electrically more often than the trip
path verification, and is taking care of this activity through other documentation of Real‐time
Fault operations.)
They start out testing all of the trip coil circuits within the prescribed Table requirements (12‐
year max) by testing the trip circuits every 10 years. The entity’s plan is to test 100 units per
year; this is greater than the minimum sample size requirement of 30. For the sake of example
only, the following will show three failures per year; reality may well have different numbers of
failures every year. PBM requires annual assessment of failures found per units tested. After
the first year of tests, the entity finds three failures in the 100 units tested. 3/100= 3% failure
rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4% failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
56
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval, and
effectively extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested / year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chosen
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
57
Please provide an example of the calculations involved in extending maintenance
time intervals using PBM for voltage and current sensing devices.
Note that the following example captures “voltage and current inputs to the protective relays”
as all of the various current transformer and potential transformer signals associated with a
particular set of relays used for protection of a specific Element. This entity calls this set of
protective relays a “Relay Scheme.” Thus, this entity chooses to count PT and CT signals as a
group instead of individually tracking maintenance activities to specific bushing CT’s or specific
PT’s. An entity is not restricted to this method of counting voltage and current devices, signals
and paths. Perhaps another method an entity would prefer would be to simply track every
individual PT and CT. Note that a generation maintenance group may well select the latter
because they may elect to perform routine off‐line tests during generator outages, whereas a
transmission maintenance group might create a process that utilizes Real‐time system values
measured at the relays. Under the included definition of “component”:
The designation of what constitutes a control circuit component is very dependent upon how an
entity performs and tracks the testing of the control circuitry. Some entities test their control
circuits on a breaker basis whereas others test their circuitry on a local zone of protection basis.
Thus, entities are allowed the latitude to designate their own definitions of control circuit
components. Another example of where the entity has some discretion on determining what
constitutes a single component is the voltage and current sensing devices, where the entity may
choose either to designate a full three‐phase set of such devices or a single device as a single
component.
And in Attachment A (PBM) the definition of Segment:
Segment –Components of a consistent design standard, or a particular model or type from a
single manufacturer that typically share other common elements. Consistent performance is
expected across the entire population of a segment. A segment must contain at least sixty (60)
individual components.
Example:
Entity has 2000 “Relay Schemes,” all of which have three current signals supplied from bushing
CTs, and three voltage signals supplied from substation bus PT’s. All cabling and circuitry was
designed and built with a consistent (internal entity) standard, and this population is greater
than the minimum sample requirement of 60.
For the sake of further example the following facts are given:
Half of all relay schemes (1,000) are supplied with current signals from ANSI STD C800 bushing
CTs and voltage signals from PTs built by ACME Electric MFR CO. All of the relay panels and
cable pulls were built with consistent standards, and consistent performance standard
expectations exist for the consistent wiring, cabling and instrument transformers within the
segment (which is greater than 60).
The other half of the entity’s relay schemes have MPC relays with additional monitoring built‐in
that compare DNP values of voltages and currents (or Watts and VARs), as interpreted by the
MPC relays and alarm for an entity‐accepted tolerance level of accuracy. This newer segment
of their “Voltage and Current Sensing” population is different than the original segment,
consistent (standards, construction and performance expectations) within the new segment
and constitutes the remainder of the entity’s population.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
58
The entity is tracking many thousands of voltage and current signals within 2,000 relay schemes
(each consisting of multiple voltage and current signals) in each of these two segments. But
half of all of the relay schemes voltage and current signals are monitored; therefore, the
voltage and current signals are continuously tested and the circuit will alarm when there is a
failure; these alarms have to be verified every 12 years for correct operation.
The entity now has 1,000 relay schemes worth of voltage and current signals remaining that
they have elected to count within their relay schemes designation. The entity has instituted a
process that requires the verification of these voltage and current signals within each relay
scheme (one unit).
(Please note ‐ a problem discovered with a current or voltage signal found at the relay could be
caused by anything from the relay, all the way to the signal source itself. Having many sources
of problems can easily increase failure rates beyond the rate of failures of just one item (for
example just PTs). It is the intent of the SDT to minimize failure rates of all of the equipment to
an acceptable level; thus, any failure of any item that gets the signal from source to relay is
counted. It is for this reason that the SDT chose to set the boundary at the ability of the signal
to be delivered all the way to the relay.
The entity will start out measuring all of the relay scheme voltage and currents at the individual
relays within the prescribed Table requirements (12 year max) by measuring the voltage and
current values every 10 years. The entity’s plan is to test 100 units per year; this is greater than
the minimum sample size requirement of 30. For the sake of example only, the following will
show three failures per year; reality may well have different numbers of failures every year.
PBM requires annual assessment of failures found per units tested. After the first year of tests,
the entity finds three failures in the 100 units tested. 3/100= 3% failure rate.
This entity is now allowed to extend the maintenance interval, if they choose. The entity
chooses to extend the maintenance interval of this population segment out to 20 years. This
represents a rate of 50 units tested per year; entity selects 50 units to be tested in the following
year. After that year of testing these 50 units, the entity again finds three failed units. 3/50=
6% failures.
This entity has now exceeded the acceptable failure rate for these devices and must accelerate
testing of all of the units at a higher rate, such that the failure rate is found to be less than 4%
per year; the entity has three years to get this failure rate down to 4% or less (per year).
In response to the 6% failure rate, the entity decreases the testing interval to 16 years. This
means that they will now test 63 units per year (1000/16). The entity has just two years left to
get the test rate corrected. After a year, they again find three failures out of the 63 units
tested. 3/63= 4.76% failures.
In response to the >4%failure rate, the entity decreases the testing interval to 14 years. This
means that they will now test 72 units per year (1000/14). The entity has just one year left to
get the test rate corrected. After a year, they again find three failures out of the 72 units
tested. 3/72= 4.2% failures.
(Note that the entity has tried 10 years, and they were under the 4% limit; and they tried 14
years, and they were over the 4% limit. They must be back at 4% failures or less in the next
year, so they might simply elect to go back to 10 years.)
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
59
Instead, in response to the 4.2% failure rate, the entity decreases the testing interval to 12
years. This means that they will now test 84 units per year (1,000/12). After a year, they again
find three failures out of the 84 units tested. 3/84= 3.6% failures.
Entity found that they could maintain the failure rate at no more than 4% failures by
maintaining the testing interval at 12 years or less. Entity chose 12‐year interval and effectively
extended their TBM (10 years) program by 20%.
A note of practicality is that an entity will probably be in better shape to lengthen the intervals
between tests if the failure rate is less than 2%. But the requirements allow for annual
adjustments, if the entity desires. As a matter of maintenance management, an ever‐changing
test rate (units tested/year) may be un‐workable.
Note that the “5% of components” requirement effectively sets a practical limit of 20‐year
maximum PBM interval. Also of note is the “3 years” requirement; an entity might arbitrarily
extend time intervals from six years to 20 years. In the event that an entity finds a failure rate
greater than 4%, then the test rate must be accelerated such that within three years the failure
rate must be brought back down to 4% or less.
Here is a table that demonstrates the values discussed:
Year #
Total
Test
Population Interval
(P)
(I)
Units to # of
be Tested Failures
Found
(U= P/I)
(F)
Failure
Rate
(=F/U)
Decision
to
Change
Interval
Interval
Chose
Yes or No
1
1000
10 yrs
100
3
3%
Yes
20 yrs
2
1000
20 yrs
50
3
6%
Yes
16yrs
3
1000
16 yrs
63
3
4.8%
Yes
14 yrs
4
1000
14 yrs
72
3
4.2%
Yes
12 yrs
5
1000
12 yrs
84
3
3.6%
No
12 yrs
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
60
10. Overlapping the Verification of Sections of the
Protection System
Tables 1‐1 through 1‐5 require that every Protection System component be periodically
verified. One approach, but not the only method, is to test the entire protection scheme as a
unit, from the secondary windings of voltage and current sources to breaker tripping. For
practical ongoing verification, sections of the Protection System may be tested or monitored
individually. The boundaries of the verified sections must overlap to ensure that there are no
gaps in the verification. See Appendix A of this Supplementary Reference for additional
discussion on this topic.
All of the methodologies expressed within this report may be combined by an entity, as
appropriate, to establish and operate a maintenance program. For example, a Protection
System may be divided into multiple overlapping sections with a different maintenance
methodology for each section:
Time‐based maintenance with appropriate maximum verification intervals for
categories of equipment, as given in the Tables 1‐1 through 1‐5;
Monitoring as described in Tables 1‐1 through 1‐5;
A Performance‐Based Maintenance program as described in Section 9 above, or
Attachment A of the standard;
Opportunistic verification using analysis of Fault records, as described in Section
11
10.1 Frequently Asked Questions:
My system has alarms that are gathered once daily through an auto-polling system;
this is not really a conventional SCADA system but does it meet the Table 1
requirements for inclusion as a monitored system?
Yes, provided the auto‐polling that gathers the alarms reports those alarms to a location where
the action can be initiated to correct the Unresolved Maintenance Issue. This location does not
have to be the location of the engineer or the technician that will eventually repair the
problem, but rather a location where the action can be initiated.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
61
11. Monitoring by Analysis of Fault Records
Many users of microprocessor relays retrieve Fault event records and oscillographic records by
data communications after a Fault. They analyze the data closely if there has been an apparent
Misoperation, as NERC standards require. Some advanced users have commissioned automatic
Fault record processing systems that gather and archive the data. They search for evidence of
component failures or setting problems hidden behind an operation whose overall outcome
seems to be correct. The relay data may be augmented with independently captured Digital
Fault Recorder (DFR) data retrieved for the same event.
Fault data analysis comprises a legitimate CBM program that is capable of reducing the need for
a manual time‐interval based check on Protection Systems whose operations are analyzed.
Even electromechanical Protection Systems instrumented with DFR channels may achieve some
CBM benefit. The completeness of the verification then depends on the number and variety of
Faults in the vicinity of the relay that produce relay response records and the specific data
captured.
A typical Fault record will verify particular parts of certain Protection Systems in the vicinity of
the Fault. For a given Protection System installation, it may or may not be possible to gather
within a reasonable amount of time an ensemble of internal and external Fault records that
completely verify the Protection System.
For example, Fault records may verify that the particular relays that tripped are able to trip via
the control circuit path that was specifically used to clear that Fault. A relay or DFR record may
indicate correct operation of the protection communications channel. Furthermore, other
nearby Protection Systems may verify that they restrain from tripping for a Fault just outside
their respective zones of protection. The ensemble of internal Fault and nearby external Fault
event data can verify major portions of the Protection System, and reset the time clock for the
Table 1 testing intervals for the verified components only.
What can be shown from the records of one operation is very specific and limited. In a panel
with multiple relays, only the specific relay(s) whose operation can be observed without
ambiguity should be used. Be careful about using Fault response data to verify that settings or
calibration are correct. Unless records have been captured for multiple Faults close to either
side of a setting boundary, setting or calibration could still be incorrect.
PMU data, much like DME data, can be utilized to prove various components of the Protection
System. Obviously, care must be taken to attribute proof only to the parts of a Protection
System that can actually be proven using the PMU or DME data.
If Fault record data is used to show that portions or all of a Protection System have been
verified to meet Table 1 requirements, the owner must retain the Fault records used, and the
maintenance‐related conclusions drawn from this data and used to defer Table 1 tests, for at
least the retention time interval given in Section 8.2.
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11.1 Frequently Asked Questions:
I use my protective relays for Fault and Disturbance recording, collecting
oscillographic records and event records via communications for Fault analysis to
meet NERC and DME requirements. What are the maintenance requirements for the
relays?
For relays used only as Disturbance Monitoring Equipment, NERC Standard PRC‐018‐1 R3 & R6
states the maintenance requirements and is being addressed by a standards activity that is
revising PRC‐002‐1 and PRC‐018‐1. For protective relays “that are designed to provide
protection for the BES,” this standard applies, even if they also perform DME functions.
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12. Importance of Relay Settings in Maintenance
Programs
In manual testing programs, many utilities depend on pickup value or zone boundary tests to
show that the relays have correct settings and calibration. Microprocessor relays, by contrast,
provide the means for continuously monitoring measurement accuracy. Furthermore, the relay
digitizes inputs from one set of signals to perform all measurement functions in a single self‐
monitoring microprocessor system. These relays do not require testing or calibration of each
setting.
However, incorrect settings may be a bigger risk with microprocessor relays than with older
relays. Some microprocessor relays have hundreds or thousands of settings, many of which are
critical to Protection System performance.
Monitoring does not check measuring element settings. Analysis of Fault records may or may
not reveal setting problems. To minimize risk of setting errors after commissioning, the user
should enforce strict settings data base management, with reconfirmation (manual or
automatic) that the installed settings are correct whenever maintenance activity might have
changed them; for background and guidance, see [5] in References.
Table 1 requires that settings must be verified to be as specified. The reason for this
requirement is simple: With legacy relays (non‐microprocessor protective relays), it is necessary
to know the value of the intended setting in order to test, adjust and calibrate the relay.
Proving that the relay works per specified setting was the de facto procedure. However, with
the advanced microprocessor relays, it is possible to change relay settings for the purpose of
verifying specific functions and then neglect to return the settings to the specified values.
While there is no specific requirement to maintain a settings management process, there
remains a need to verify that the settings left in the relay are the intended, specified settings.
This need may manifest itself after any of the following:
One or more settings are changed for any reason.
A relay fails and is repaired or replaced with another unit.
A relay is upgraded with a new firmware version.
12.1 Frequently Asked Questions:
How do I approach testing when I have to upgrade firmware of a microprocessor
relay?
The entity should ensure that the relay continues to function properly after implementation of
firmware changes. Some entities may have a R&D department that might routinely run
acceptance tests on devices with firmware upgrades before allowing the upgrade to be
installed. Other entities may rely upon the vigorous testing of the firmware OEM. An entity has
the latitude to install devices and/or programming that they believe will perform to their
satisfaction. If an entity should choose to perform the maintenance activities specified in the
Tables following a firmware upgrade, then they may, if they choose, reset the time clock on
that set of maintenance activities so that they would not have to repeat the maintenance on its
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regularly scheduled cycle. (However, for simplicity in maintenance schedules, some entities
may choose to not reset this time clock; it is merely a suggested option.)
If I upgrade my old relays, then do I have to maintain my previous equipment
maintenance documentation?
If an equipment item is repaired or replaced, then the entity can restart the maintenance‐
activity‐time‐interval‐clock, if desired; however, the replacement of equipment does not
remove any documentation requirements. The requirements in the standard are intended to
ensure that an entity has a maintenance plan, and that the entity adheres to minimum activities
and maximum time intervals. The documentation requirements are intended to help an entity
demonstrate compliance. For example, saving the dates and records of the last two
maintenance activities is intended to demonstrate compliance with the interval. Therefore, if
you upgrade or replace equipment, then you still must maintain the documentation for the
previous equipment, thus demonstrating compliance with the time interval requirement prior
to the replacement action.
We have a number of installations where we have changed our Protection System
components. Some of the changes were upgrades, but others were simply system
rating changes that merely required taking relays “out-of-service”. What are our
responsibilities when it comes to “out-of-service” devices?
Assuming that your system up‐rates, upgrades and overall changes meet any and all other
requirements and standards, then the requirements of PRC‐005‐3 are simple – if the Protection
System component performs a Protection System function, then it must be maintained. If the
component no longer performs Protection System functions, then it does not require
maintenance activities under the Tables of PRC‐005‐3. While many entities might physically
remove a component that is no longer needed, there is no requirement in PRC‐005‐3 to remove
such component(s). Obviously, prudence would dictate that an “out‐of‐service” device is truly
made inactive. There are no record requirements listed in PRC‐005‐3 for Protection System
components not used.
While performing relay testing of a protective device on our Bulk Electric System, it
was discovered that the protective device being tested was either broken or out of
calibration. Does this satisfy the relay testing requirement, even though the
protective device tested bad, and may be unable to be placed back into service?
Yes, PRC‐005‐3 requires entities to perform relay testing on protective devices on a given
maintenance cycle interval. By performing this testing, the entity has satisfied PRC‐005‐3
requirement, although the protective device may be unable to be returned to service under
normal calibration adjustments. R5 states:
“R5. Each Transmission Owner, Generator Owner, and Distribution Provider shall demonstrate
efforts to correct any identified Unresolved Maintenance Issues.”
Also, when a failure occurs in a Protection System, power system security may be comprised,
and notification of the failure must be conducted in accordance with relevant NERC standards.
If I show the protective device out of service while it is being repaired, then can I
add it back as a new protective device when it returns? If not, my relay testing
history would show that I was out of compliance for the last maintenance cycle.
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The maintenance and testing requirements (R5) state “…shall demonstrate efforts to correct
any identified Unresolved Maintenance Issues...” The type of corrective activity is not stated;
however, it could include repairs or replacements.
Your documentation requirements will increase, of course, to demonstrate that your device
tested bad and had corrective actions initiated. Your regional entity might ask about the status
of your corrective actions.
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13. Self-Monitoring Capabilities and Limitations
Microprocessor relay proponents have cited the self‐monitoring capabilities of these products
for nearly 20 years. Theoretically, any element that is monitored does not need a periodic
manual test. A problem today is that the community of manufacturers and users has not
created clear documentation of exactly what is and is not monitored. Some unmonitored but
critical elements are buried in installed systems that are described as self‐monitoring.
To utilize the extended time intervals allowed by monitoring, the user must document that the
monitoring attributes of the device match the minimum requirements listed in the Table 1.
Until users are able to document how all parts of a system which are required for the protective
functions are monitored or verified (with help from manufacturers), they must continue with
the unmonitored intervals established in Table 1 and Table 3.
Going forward, manufacturers and users can develop mappings of the monitoring within relays,
and monitoring coverage by the relay of user circuits connected to the relay terminals.
To enable the use of the most extensive monitoring (and never again have a hands‐on
maintenance requirement), the manufacturers of the microprocessor‐based self‐monitoring
components in the Protection System should publish for the user a document or map that
shows:
How all internal elements of the product are monitored for any failure that could
impact Protection System performance.
Which connected circuits are monitored by checks implemented within the
product; how to connect and set the product to assure monitoring of these
connected circuits; and what circuits or potential problems are not monitored.
This manufacturer’s information can be used by the registered entity to document compliance
of the monitoring attributes requirements by:
Presenting or referencing the product manufacturer’s documents.
Explaining in a system design document the mapping of how every component
and circuit that is critical to protection is monitored by the microprocessor
product(s) or by other design features.
Extending the monitoring to include the alarm transmission Facilities through
which failures are reported within a given time frame to allocate where action
can be taken to initiate resolution of the alarm attributed to an Unresolved
Maintenance Issue, so that failures of monitoring or alarming systems also lead
to alarms and action.
Documenting the plans for verification of any unmonitored components
according to the requirements of Table 1 and Table 3.
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13.1 Frequently Asked Questions:
I can’t figure out how to demonstrate compliance with the requirements for the
highest level of monitoring of Protection Systems. Why does this Maintenance
Standard describe a maintenance program approach I cannot achieve?
Demonstrating compliance with the requirements for the highest level of monitoring any
particular component of Protection Systems is likely to be very involved, and may include
detailed manufacturer documentation of complete internal monitoring within a device,
comprehensive design drawing reviews, and other detailed documentation. This standard does
not presume to specify what documentation must be developed; only that it must be
documented.
There may actually be some equipment available that is capable of meeting these highest levels
of monitoring criteria, in which case it may be maintained according to the highest level of
monitoring shown on the Tables. However, even if there is no equipment available today that
can meet this level of monitoring, the standard establishes the necessary requirements for
when such equipment becomes available.
By creating a roadmap for development, this provision makes the standard technology‐neutral.
The Standard Drafting Team wants to avoid the need to revise the standard in a few years to
accommodate technology advances that may be coming to the industry.
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14. Notification of Protection System or Automatic
Reclosing Failures
When a failure occurs in a Protection System or Automatic Reclosing, power system security
may be compromised, and notification of the failure must be conducted in accordance with
relevant NERC standard(s). Knowledge of the failure may impact the system operator’s
decisions on acceptable Loading conditions.
This formal reporting of the failure and repair status to the system operator by the Protection
System or Automatic Reclosing owner also encourages the system owner to execute repairs as
rapidly as possible. In some cases, a microprocessor relay or carrier set can be replaced in
hours; wiring termination failures may be repaired in a similar time frame. On the other hand,
a component in an electromechanical or early‐generation electronic relay may be difficult to
find and may hold up repair for weeks. In some situations, the owner may have to resort to a
temporary protection panel, or complete panel replacement.
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15. Maintenance Activities
Some specific maintenance activities are a requirement to ensure reliability. An example would
be that a BES entity could be prudent in its protective relay maintenance, but if its battery
maintenance program is lacking, then reliability could still suffer. The NERC glossary outlines a
Protection System as containing specific components. PRC‐005‐3 requires specific maintenance
activities be accomplished within a specific time interval. As noted previously, higher
technology equipment can contain integral monitoring capability that actually performs
maintenance verification activities routinely and often; therefore, manual intervention to
perform certain activities on these type components may not be needed.
15.1 Protective Relays (Table 1-1)
These relays are defined as the devices that receive the input signal from the current and
voltage sensing devices and are used to isolate a Faulted Element of the BES. Devices that
sense thermal, vibration, seismic, pressure, gas, or any other non‐electrical inputs are excluded.
Non‐microprocessor based equipment is treated differently than microprocessor‐based
equipment in the following ways; the relays should meet the asset owners’ tolerances:
Non‐microprocessor devices must be tested with voltage and/or current applied to the
device.
Microprocessor devices may be tested through the integral testing of the device.
o There is no specific protective relay commissioning test or relay routine test
mandated.
o There is no specific documentation mandated.
15.1.1 Frequently Asked Questions:
What calibration tolerance should be applied on electromechanical relays?
Each entity establishes their own acceptable tolerances when applying protective relaying on
their system. For some Protection System components, adjustment is required to bring
measurement accuracy within the parameters established by the asset owner based on the
specific application of the component. A calibration failure is the result if testing finds the
specified parameters to be out of tolerance.
15.2 Voltage & Current Sensing Devices (Table 1-3)
These are the current and voltage sensing devices, usually known as instrument transformers.
There is presently a technology available (fiber‐optic Hall‐effect) that does not utilize
conventional transformer technology; these devices and other technologies that produce
quantities that represent the primary values of voltage and current are considered to be a type
of voltage and current sensing devices included in this standard.
The intent of the maintenance activity is to verify the input to the protective relay from the
device that produces the current or voltage signal sample.
There is no specific test mandated for these components. The important thing about these
signals is to know that the expected output from these components actually reaches the
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protective relay. Therefore, the proof of the proper operation of these components also
demonstrates the integrity of the wiring (or other medium used to convey the signal) from the
current and voltage sensing device, all the way to the protective relay. The following
observations apply:
There is no specific ratio test, routine test or commissioning test mandated.
There is no specific documentation mandated.
It is required that the signal be present at the relay.
This expectation can be arrived at from any of a number of means; including, but not
limited to, the following: By calculation, by comparison to other circuits, by
commissioning tests, by thorough inspection, or by any means needed to verify the
circuit meets the asset owner’s Protection System maintenance program.
An example of testing might be a saturation test of a CT with the test values applied at
the relay panel; this, therefore, tests the CT, as well as the wiring from the relay all the
back to the CT.
Another possible test is to measure the signal from the voltage and/or current sensing
devices, during Load conditions, at the input to the relay.
Another example of testing the various voltage and/or current sensing devices is to
query the microprocessor relay for the Real‐time Loading; this can then be compared to
other devices to verify the quantities applied to this relay. Since the input devices have
supplied the proper values to the protective relay, then the verification activity has been
satisfied. Thus, event reports (and oscillographs) can be used to verify that the voltage
and current sensing devices are performing satisfactorily.
Still another method is to measure total watts and vars around the entire bus; this
should add up to zero watts and zero vars, thus proving the voltage and/or current
sensing devices system throughout the bus.
Another method for proving the voltage and/or current‐sensing devices is to complete
commissioning tests on all of the transformers, cabling, fuses and wiring.
Any other method that verifies the input to the protective relay from the device that
produces the current or voltage signal sample.
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15.2.1 Frequently Asked Questions:
What is meant by “…verify the current and voltage circuit inputs from the voltage
and current sensing devices to the protective relays …”
Do we need to perform
ratio, polarity and saturation tests every few years?
No. You must verify that the protective relay is receiving the expected values from the voltage
and current‐sensing devices (typically voltage and current transformers). This can be as difficult
as is proposed by the question (with additional testing on the cabling and substation wiring to
ensure that the values arrive at the relays); or simplicity can be achieved by other verification
methods. While some examples follow, these are not intended to represent an all‐inclusive list;
technology advances and ingenuity should not be excluded from making comparisons and
verifications:
Compare the secondary values, at the relay, to a metering circuit, fed by different
current transformers, monitoring the same line as the questioned relay circuit.
Compare the individual phase secondary values at the relay panel (with additional
testing on the panel wiring to ensure that the values arrive at those relays) with the
other phases, and verify that residual currents are within expected bounds.
Observe all three phase currents and the residual current at the relay panel with an
oscilloscope, observing comparable magnitudes and proper phase relationship, with
additional testing on the panel wiring to ensure that the values arrive at the relays.
Compare the values, as determined by the questioned relay (such as, but not limited to,
a query to the microprocessor relay) to another protective relay monitoring the same
line, with currents supplied by different CTs.
Compare the secondary values, at the relay with values measured by test instruments
(such as, but not limited to multi‐meters, voltmeter, clamp‐on ammeters, etc.) and
verified by calculations and known ratios to be the values expected. For example, a
single PT on a 100KV bus will have a specific secondary value that, when multiplied by
the PT ratio, arrives at the expected bus value of 100KV.
Query SCADA for the power flows at the far end of the line protected by the questioned
relay, compare those SCADA values to the values as determined by the questioned
relay.
Totalize the Watts and VARs on the bus and compare the totals to the values as seen by
the questioned relay.
The point of the verification procedure is to ensure that all of the individual components are
functioning properly; and that an ongoing proactive procedure is in place to re‐check the
various components of the protective relay measuring Systems.
Is wiring insulation or hi-pot testing required by this Maintenance Standard?
No, wiring insulation and equipment hi‐pot testing are not specifically required by the
Maintenance Standard. However, if the method of verifying CT and PT inputs to the relay
involves some other method than actual observation of current and voltage transformer
secondary inputs to the relay, it might be necessary to perform some sort of cable integrity test
to verify that the instrument transformer secondary signals are actually making it to the relay
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and not being shunted off to ground. For instance, you could use CT excitation tests and PT
turns ratio tests and compare to baseline values to verify that the instrument transformer
outputs are acceptable. However, to conclude that these acceptable transformer instrument
output signals are actually making it to the relay inputs, it also would be necessary to verify the
insulation of the wiring between the instrument transformer and the relay.
My plant generator and transformer relays are electromechanical and do not have
metering functions, as do microprocessor- based relays. In order for me to compare
the instrument transformer inputs to these relays to the secondary values of other
metered instrument transformers monitoring the same primary voltage and current
signals, it would be necessary to temporarily connect test equipment, like
voltmeters and clamp on ammeters, to measure the input signals to the relays. This
practice seems very risky, and a plant trip could result if the technician were to
make an error while measuring these current and voltage signals. How can I avoid
this risk? Also, what if no other instrument transformers are available which
monitor the same primary voltage or current signal?
Comparing the input signals to the relays to the outputs of other independent instrument
transformers monitoring the same primary current or voltage is just one method of verifying
the instrument transformer inputs to the relays, but is not required by the standard. Plants can
choose how to best manage their risk. If online testing is deemed too risky, offline tests, such
as, but not limited to, CT excitation test and PT turns ratio tests can be compared to baseline
data and be used in conjunction with CT and PT secondary wiring insulation verification tests to
adequately “verify the current and voltage circuit inputs from the voltage and current sensing
devices to the protective relays …” while eliminating the risk of tripping an in service generator
or transformer. Similarly, this same offline test methodology can be used to verify the relay
input voltage and current signals to relays when there are no other instrument transformers
monitoring available for purposes of signal comparison.
15.3 Control circuitry associated with protective functions (Table 1-5)
This component of Protection Systems includes the trip coil(s) of the circuit breaker, circuit
switcher or any other interrupting device. It includes the wiring from the batteries to the
relays. It includes the wiring (or other signal conveyance) from every trip output to every trip
coil. It includes any device needed for the correct processing of the needed trip signal to the
trip coil of the interrupting device; this requirement is meant to capture inputs and outputs to
and from a protective relay that are necessary for the correct operation of the protective
functions. In short, every trip path must be verified; the method of verification is optional to
the asset owner. An example of testing methods to accomplish this might be to verify, with a
volt‐meter, the existence of the proper voltage at the open contacts, the open circuited input
circuit and at the trip coil(s). As every parallel trip path has similar failure modes, each trip path
from relay to trip coil must be verified. Each trip coil must be tested to trip the circuit breaker
(or other interrupting device) at least once. There is a requirement to operate the circuit
breaker (or other interrupting device) at least once every six years as part of the complete
functional test. If a suitable monitoring system is installed that verifies every parallel trip path,
then the manual‐intervention testing of those parallel trip paths can be eliminated; however,
the actual operation of the circuit breaker must still occur at least once every six years. This six‐
year tripping requirement can be completed as easily as tracking the Real‐time Fault‐clearing
operations on the circuit breaker, or tracking the trip coil(s) operation(s) during circuit breaker
routine maintenance actions.
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The circuit‐interrupting device should not be confused with a motor‐operated disconnect. The
intent of this standard is to require maintenance intervals and activities on Protection Systems
equipment, and not just all system isolating equipment.
It is necessary, however, to classify a device that actuates a high‐speed auto‐closing ground
switch as an interrupting device, if this ground switch is utilized in a Protection System and
forces a ground Fault to occur that then results in an expected Protection System operation to
clear the forced ground Fault. The SDT believes that this is essentially a transferred‐tripping
device without the use of communications equipment. If this high‐speed ground switch is
“…designed to provide protection for the BES…” then this device needs to be treated as any
other Protection System component. The control circuitry would have to be tested within 12
years, and any electromechanically operated device will have to be tested every six years. If the
spring‐operated ground switch can be disconnected from the solenoid triggering unit, then the
solenoid triggering unit can easily be tested without the actual closing of the ground blade.
The dc control circuitry also includes each auxiliary tripping relay (94) and each lock‐out relay
(86) that may exist in any particular trip scheme. If the lock‐out relays (86) are
electromechanical type components, then they must be trip tested. The PSMT SDT considers
these components to share some similarities in failure modes as electromechanical protective
relays; as such, there is a six‐year maximum interval between mandated maintenance tasks
unless PBM is applied.
Contacts of the 86 and/or 94 that pass the trip current on to the circuit interrupting device trip
coils will have to be checked as part of the 12 year requirement. Contacts of the 86 and/or 94
lock relay that operate non‐BES interrupting devices are not required. Normally‐open contacts
that are not used to pass a trip signal and normally‐closed contacts do not have to be verified.
Verification of the tripping paths is the requirement.
While relays that do not respond to electrical quantities are presently excluded from this
standard, their control circuits are included if the relay is installed to detect Faults on BES
Elements. Thus, the control circuit of a BES transformer sudden pressure relay should be
verified every 12 years, assuming its integrity is not monitored. While a sudden pressure relay
control circuit is included within the scope of PRC‐005‐2, other alarming relay control circuits,
(i.e., SF‐6 low gas) are not included, even though they may trip the breaker being monitored.
New technology is also accommodated here; there are some tripping systems that have
replaced the traditional hard‐wired trip circuitry with other methods of trip‐signal conveyance
such as fiber‐optics. It is the intent of the PSMT SDT to include this, and any other, technology
that is used to convey a trip signal from a protective relay to a circuit breaker (or other
interrupting device) within this category of equipment. The requirement for these systems is
verification of the tripping path.
Monitoring of the control circuit integrity allows for no maintenance activity on the control
circuit (excluding the requirement to operate trip coils and electromechanical lockout and/or
tripping auxiliary relays). Monitoring of integrity means to monitor for continuity and/or
presence of voltage on each trip path. For Ethernet or fiber‐optic control systems, monitoring
of integrity means to monitor communication ability between the relay and the circuit breaker.
The trip path from a sudden pressure device is a part of the Protection System control circuitry.
The sensing element is omitted from PRC‐005‐3 testing requirements because the SDT is
unaware of industry‐recognized testing protocol for the sensing elements. The SDT believes
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that Protection Systems that trip (or can trip) the BES should be included. This position is
consistent with the currently‐approved PRC‐005‐1b, consistent with the SAR for Project 2007‐
17, and understands this to be consistent with the position of FERC staff.
15.3.1 Frequently Asked Questions:
Is it permissible to verify circuit breaker tripping at a different time (and interval)
than when we verify the protective relays and the instrument transformers?
Yes, provided the entire Protective System is tested within the individual component’s
maximum allowable testing intervals.
The Protection System Maintenance Standard describes requirements for verifying
the tripping of circuit breakers. What is this telling me about maintenance of circuit
breakers?
Requirements in PRC‐005‐3 are intended to verify the integrity of tripping circuits, including the
breaker trip coil, as well as the presence of auxiliary supply (usually a battery) for energizing the
trip coil if a protection function operates. Beyond this, PRC‐005‐3 sets no requirements for
verifying circuit breaker performance, or for maintenance of the circuit breaker.
How do I test each dc Control Circuit trip path, as established in Table 1-5
“Protection System Control Circuitry (Trip coils and auxiliary relays)”?
Table 1‐5 specifies that each breaker trip coil and lockout relays that carry trip current to
a trip coil must be operated within the specified time period. The required operations
may be via targeted maintenance activities, or by documented operation of these
devices for other purposes such as Fault clearing.
Are high-speed ground switch trip coils included in the dc control circuitry?
Yes. PRC‐005‐3 includes high‐speed grounding switch trip coils within the dc control circuitry to
the degree that the initiating Protection Systems are characterized as “transmission Protection
Systems.”
Does the control circuitry and trip coil of a non-BES breaker, tripped via a BES
protection component, have to be tested per Table 1.5? (Refer to Table 3 for
examples 1 and 2) Example 1: A non‐BES circuit breaker that is tripped via a Protection
System to which PRC‐005‐3 applies might be (but is not limited to) a 12.5KV circuit breaker
feeding (non‐black‐start) radial Loads but has a trip that originates from an under‐frequency
(81) relay.
The relay must be verified.
The voltage signal to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
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The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
Example 2: A Transmission Owner may have a non‐BES breaker that is tripped via a Protection
System to which PRC‐005‐3 applies, which may be (but is not limited to) a 13.8 KV circuit
breaker feeding (non‐black‐start) radial Loads but has a trip that originates from a BES 115KV
line relay.
The relay must be verified
The voltage signal to the relay must be verified
All of the relevant dc supply tests still apply
The unmonitored trip circuit between the relay and any lock‐out (86) or auxiliary (94)
relay must be verified every 12 years
The unmonitored trip circuit between the lock‐out (86) (or auxiliary (94)) relay and the
non‐BES breaker does not have to be proven with an electrical trip
In the case where there is no lockout (86) or auxiliary (94) tripping relay used, the trip
circuit to the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip
Example 3: A Generator Owner may have an non‐BES circuit breaker that is tripped via a
Protection System to which PRC‐005‐3 applies, such as the generator field breaker and low‐side
breakers on station service/excitation transformers connected to the generator bus.
Trip testing of the generator field breaker and low side station service/excitation transformer
breaker(s) via lockout or auxiliary tripping relays are not required since these breakers may be
associated with radially fed loads and are not considered to be BES breakers. An example of an
otherwise non‐BES circuit breaker that is tripped via a BES protection component might be (but
is not limited to) a 6.9kV station service transformer source circuit breaker but has a trip that
originates from a generator differential (87) relay.
The differential relay must be verified.
The current signals to the relay must be verified.
All of the relevant dc supply tests still apply.
The unmonitored trip circuit between the relay and any lock‐out or auxiliary relay must
be verified every 12 years.
The unmonitored trip circuit between the lock‐out (or auxiliary relay) and the non‐BES
breaker does not have to be proven with an electrical trip.
In the case where there is no lock‐out or auxiliary tripping relay used, the trip circuit to
the non‐BES breaker does not have to be proven with an electrical trip.
The trip coil of the non‐BES circuit breaker does not have to be individually proven with
an electrical trip.
However, it is very prudent to verify the tripping of such breakers for the integrity of the overall
generation plant.
Do I have to verify operation of breaker “a” contacts or any other normally closed
auxiliary contacts in the trip path of each breaker as part of my control circuit test?
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Operation of normally‐closed contacts does not have to be verified. Verification of the tripping
paths is the requirement. The continuity of the normally closed contacts will be verified when
the tripping path is verified.
15.4 Batteries and DC Supplies (Table 1-4)
The NERC definition of a Protection System is:
Protective relays which respond to electrical quantities,
Communications Systems necessary for correct operation of protective functions,
Voltage and current sensing devices providing inputs to protective relays,
Station dc supply associated with protective functions (including station batteries,
battery chargers, and non‐battery‐based dc supply), and
Control circuitry associated with protective functions through the trip coil(s) of the
circuit breakers or other interrupting devices.
The station battery is not the only component that provides dc power to a Protection System.
In the new definition for Protection System, “station batteries” are replaced with “station dc
supply” to make the battery charger and dc producing stored energy devices (that are not a
battery) part of the Protection System that must be maintained.
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity of a battery set by various methods, and not to limit the owner
to other conventional methods of showing continuity. Continuity, as used in Table 1‐4 of the
standard, refers to verifying that there is a continuous current path from the positive terminal
of the station battery set to the negative terminal. Without verifying continuity of a station
battery, there is no way to determine that the station battery is available to supply dc power to
the station. An open battery string will be an unavailable power source in the event of loss of
the battery charger.
Batteries cannot be a unique population segment of a Performance‐Based Maintenance
Program (PBM) because there are too many variables in the electrochemical process to
completely isolate all of the performance‐changing criteria necessary for using PBM on battery
Systems. However, nothing precludes the use of a PBM process for any other part of a dc
supply besides the batteries themselves.
15.4.1 Frequently Asked Questions:
What constitutes the station dc supply, as mentioned in the definition of Protective
System?
The previous definition of Protection System includes batteries, but leaves out chargers. The
latest definition includes chargers, as well as dc systems that do not utilize batteries. This
revision of PRC‐005‐3 is intended to capture these devices that were not included under the
previous definition. The station direct current (dc) supply normally consists of two
components: the battery charger and the station battery itself. There are also emerging
technologies that provide a source of dc supply that does not include either a battery or
charger.
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Battery Charger ‐ The battery charger is supplied by an available ac source. At a minimum, the
battery charger must be sized to charge the battery (after discharge) and supply the constant dc
load. In many cases, it may be sized also to provide sufficient dc current to handle the higher
energy requirements of tripping breakers and switches when actuated by the protective relays
in the Protection System.
Station Battery ‐ Station batteries provide the dc power required for tripping and for supplying
normal dc power to the station in the event of loss of the battery charger. There are several
technologies of battery that require unique forms of maintenance as established in Table 1‐4.
Emerging Technologies ‐ Station dc supplies are currently being developed that use other
energy storage technologies besides the station battery to prevent loss of the station dc supply
when ac power is lost. Maintenance of these station dc supplies will require different kinds of
tests and inspections. Table 1‐4 presents maintenance activities and maximum allowable
testing intervals for these new station dc supply technologies. However, because these
technologies are relatively new, the maintenance activities for these station dc supplies may
change over time.
What did the PSMT SDT mean by “continuity” of the dc supply?
The PSMT SDT recognizes that there are several technological advances in equipment and
testing procedures that allow the owner to choose how to verify that a battery string is free of
open circuits. The term “continuity” was introduced into the standard to allow the owner to
choose how to verify continuity (no open circuits) of a battery set by various methods, and not
to limit the owner to other conventional methods of showing continuity – lack of an open
circuit. Continuity, as used in Table 1‐4 of the standard, refers to verifying that there is a
continuous current path from the positive terminal of the station battery set to the negative
terminal (no open circuit). Without verifying continuity of a station battery, there is no way to
determine that the station battery is available to supply dc power to the station. Whether it is
caused from an open cell or a bad external connection, an open battery string will be an
unavailable power source in the event of loss of the battery charger.
The current path through a station battery from its positive to its negative connection to the dc
control circuits is composed of two types of elements. These path elements are the
electrochemical path through each of its cells and all of the internal and external metallic
connections and terminations of the batteries in the battery set. If there is loss of continuity
(an open circuit) in any part of the electrochemical or metallic path, the battery set will not be
available for service. In the event of the loss of the ac source or battery charger, the battery
must be capable of supplying dc current, both for continuous dc loads and for tripping breakers
and switches. Without continuity, the battery cannot perform this function.
At generating stations and large transmission stations where battery chargers are capable of
handling the maximum current required by the Protection System, there are still problems that
could potentially occur when the continuity through the connected battery is interrupted.
Many battery chargers produce harmonics which can cause failure of dc power supplies
in microprocessor‐based protective relays and other electronic devices connected to
station dc supply. In these cases, the substation battery serves as a filter for these
harmonics. With the loss of continuity in the battery, the filter provided by the battery
is no longer present.
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Loss of electrical continuity of the station battery will cause, in most battery chargers,
regardless of the battery charger’s output current capability, a delayed response in full
output current from the charger. Almost all chargers have an intentional one‐ to two‐
second delay to switch from a low substation dc load current to the maximum output of
the charger. This delay would cause the opening of circuit breakers to be delayed,
which could violate system performance standards.
Monitoring of the station dc supply voltage will not indicate that there is a problem with the dc
current path through the battery, unless the battery charger is taken out of service. At that
time, a break in the continuity of the station battery current path will be revealed because
there will be no voltage on the station dc circuitry. This particular test method, while proving
battery continuity, may not be acceptable to all installations.
Although the standard prescribes what must be accomplished during the maintenance activity,
it does not prescribe how the maintenance activity should be accomplished. There are several
methods that can be used to verify the electrical continuity of the battery. These are not the
only possible methods, simply a sampling of some methods:
One method is to measure that there is current flowing through the battery itself by a
simple clamp on milliamp‐range ammeter. A battery is always either charging or
discharging. Even when a battery is charged, there is still a measurable float charge
current that can be detected to verify that there is continuity in the electrical path
through the battery.
A simple test for continuity is to remove the battery charger from service and verify that
the battery provides voltage and current to the dc system. However, the behavior ofthe
various dc‐supplied equipment in the station should be considered before using this
approach.
Manufacturers of microprocessor‐controlled battery chargers have developed methods
for their equipment to periodically (or continuously) test for battery continuity. For
example, one manufacturer periodically reduces the float voltage on the battery until
current from the battery to the dc load can be measured to confirm continuity.
Applying test current (as in some ohmic testing devices, or devices for locating dc
grounds) will provide a current that when measured elsewhere in the string, will prove
that the circuit is continuous.
Internal ohmic measurements of the cells and units of lead‐acid batteries (VRLA & VLA)
can detect lack of continuity within the cells of a battery string; and when used in
conjunction with resistance measurements of the battery’s external connections, can
prove continuity. Also some methods of taking internal ohmic measurements, by their
very nature, can prove the continuity of a battery string without having to use the
results of resistance measurements of the external connections.
Specific gravity tests could infer continuity because without continuity there could be no
charging occurring; and if there is no charging, then specific gravity will go down below
acceptable levels over time.
No matter how the electrical continuity of a battery set is verified, it is a necessary maintenance
activity that must be performed at the intervals prescribed by Table 1‐4 to insure that the
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station dc supply has a path that can provide the required current to the Protection System at
all times.
When should I check the station batteries to see if they have sufficient energy to
perform as manufactured?
The answer to this question depends on the type of battery (valve‐regulated lead‐acid, vented
lead‐acid, or nickel‐cadmium) and the maintenance activity chosen.
For example, if you have a valve‐regulated lead‐acid (VRLA) station battery, and you have
chosen to evaluate the measured cell/unit internal ohmic values to the battery cell’s baseline,
you will have to perform verification at a maximum maintenance interval of no greater than
every six months. While this interval might seem to be quite short, keep in mind that the six‐
month interval is important for VRLA batteries; this interval provides an accumulation of data
that better shows when a VRLA battery is incapable of performing as manufactured.
If, for a VRLA station battery, you choose to conduct a performance capacity test on the entire
station battery as the maintenance activity, then you will have to perform verification at a
maximum maintenance interval of no greater than every three calendar years.
How is a baseline established for cell/unit internal ohmic measurements?
Establishment of cell/unit internal ohmic baseline measurements should be completed when
lead‐acid batteries are newly installed. To ensure that the baseline ohmic cell/unit values are
most indicative of the station battery’s ability to perform as manufactured, they should be
made at some point in time after the installation to allow the cell chemistry to stabilize after
the initial freshening charge. An accepted industry practice for establishing baseline values is
after six‐months of installation, with the battery fully charged and in service. However, it is
recommended that each owner, when establishing a baseline, should consult the battery
manufacturer for specific instructions on establishing an ohmic baseline for their product, if
available.
When internal ohmic measurements are taken, the same make/model test equipment should
be used to establish the baseline and used for the future trending of the cells internal ohmic
measurements because of variances in test equipment and the type of ohmic measurement
used by different manufacturer’s equipment. Keep in mind that one manufacturer’s
“Conductance” test equipment does not produce similar results as another manufacturer’s
“Conductance” test equipment, even though both manufacturers have produced “Ohmic” test
equipment. Therefore, for meaningful results to an established baseline, the same
make/model of instrument should be used.
For all new installations of valve‐regulated lead‐acid (VRLA) batteries and vented lead‐acid
(VLA) batteries, where trending of the cells internal ohmic measurements to a baseline are to
be used to determine the ability of the station battery to perform as manufactured, the
establishment of the baseline, as described above, should be followed at the time of installation
to insure the most accurate trending of the cell/unit. However, often for older VRLA batteries,
the owners of the station batteries have not established a baseline at installation. Also for
owners of VLA batteries who want to establish a maintenance activity which requires trending
of measured ohmic values to a baseline, there was typically no baseline established at
installation of the station battery to trend to.
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To resolve the problem of the unavailability of baseline internal ohmic measurements for the
individual cell/unit of a station battery, many manufacturers of internal ohmic measurement
devices have established libraries of baseline values for VRLA and VLA batteries using their
testing device. Also, several of the battery manufacturers have libraries of baselines for their
products that can be used to trend to. However, it is important that when using battery
manufacturer‐supplied data that it is verified that the baseline readings to be used were taken
with the same ohmic testing device that will be used for future measurements (for example
“Conductance Readings” from one manufacturer’s test equipment do not correlate to
“Impedance Readings” from a different manufacturer’s test equipment). Although many
manufacturers may have provided baseline values, which will allow trending of the internal
ohmic measurements over the remaining life of a station battery, these baselines are not the
actual cell/unit measurements for the battery being trended. It is important to have a baseline
tailored to the station battery to more accurately use the tool of ohmic measurement trending.
That more customized baseline can only be created by following the establishment of a
baseline for each cell/unit at the time of installation of the station battery.
Why determine the State of Charge?
Even though there is no present requirement to check the state of charge of a battery, it can be
a very useful tool in determining the overall condition of a battery system. The following
discussions are offered as a general reference.
When a battery is fully charged, the battery is available to deliver its existing capacity. As a
battery is discharged, its ability to deliver its maximum available capacity is diminished. It is
necessary to determine if the state of charge has dropped to an unacceptable level.
What is State of Charge and how can it be determined in a station battery?
The state of charge of a battery refers to the ratio of residual capacity at a given instant to the
maximum capacity available from the battery. When a battery is fully charged, the battery is
available to deliver its existing capacity. As a battery is discharged, its ability to deliver its
maximum available capacity is diminished. Knowing the amount of energy left in a battery
compared with the energy it had when it was fully charged gives the user an indication of how
much longer a battery will continue to perform before it needs recharging.
For vented lead‐acid (VLA) batteries which use accessible liquid electrolyte, a hydrometer can
be used to test the specific gravity of each cell as a measure of its state of charge. The
hydrometer depends on measuring changes in the weight of the active chemicals. As the
battery discharges, the active electrolyte, sulfuric acid, is consumed and the concentration of
the sulfuric acid in water is reduced. This, in turn, reduces the specific gravity of the solution in
direct proportion to the state of charge. The actual specific gravity of the electrolyte can,
therefore, be used as an indication of the state of charge of the battery. Hydrometer readings
may not tell the whole story, as it takes a while for the acid to get mixed up in the cells of a VLA
battery. If measured right after charging, you might see high specific gravity readings at the top
of the cell, even though it is much less at the bottom. Conversely, if taken shortly after adding
water to the cell, the specific gravity readings near the top of the cell will be lower than those
at the bottom.
Nickel‐cadmium batteries, where the specific gravity of the electrolyte does not change during
battery charge and discharge, and valve‐regulated lead‐acid (VRLA) batteries, where the
electrolyte is not accessible, cannot have their state of charge determined by specific gravity
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readings. For these two types of batteries, and for VLA batteries also, where another method
besides taking hydrometer readings is desired, the state of charge may be determined by taking
voltage and current readings at the battery terminals. The methods employed to obtain
accurate readings vary for the different battery types. Manufacturers’ information and IEEE
guidelines can be consulted for specifics; (see IEEE 1106 Annex B for Nickel Cadmium batteries,
IEEE 1188 Annex A for VRLA batteries and IEEE 450 for VLA batteries.
Why determine the Connection Resistance?
High connection resistance can cause abnormal voltage drop or excessive heating during
discharge of a station battery. During periods of a high rate of discharge of the station battery,
a very high resistance can cause severe damage. The maintenance requirement to verify
battery terminal connection resistance in Table 1‐4 is established to verify that the integrity of
all battery electrical connections is acceptable. This verification includes cell‐to‐cell (intercell)
and external circuit terminations. Your method of checking for acceptable values of intercell
and terminal connection resistance could be by individual readings, or a combination of the
two. There are test methods presently that can read post termination resistances and
resistance values between external posts. There are also test methods presently available that
take a combination reading of the post termination connection resistance plus the intercell
resistance value plus the post termination connection resistance value. Either of the two
methods, or any other method, that can show if the adequacy of connections at the battery
posts is acceptable.
Adequacy of the electrical terminations can be determined by comparing resistance
measurements for all connections taken at the time of station battery’s installation to the same
resistance measurements taken at the maintenance interval chosen, not to exceed the
maximum maintenance interval of Table 1‐4. Trending of the interval measurements to the
baseline measurements will identify any degradation in the battery connections. When the
connection resistance values exceed the acceptance criteria for the connection, the connection
is typically disassembled, cleaned, reassembled and measurements taken to verify that the
measurements are adequate when compared to the baseline readings.
What conditions should be inspected for visible battery cells?
The maintenance requirement to inspect the cell condition of all station battery cells where the
cells are visible is a maintenance requirement of Table 1‐4. Station batteries are different from
any other component in the Protection Station because they are a perishable product due to
the electrochemical process which is used to produce dc electrical current and voltage. This
inspection is a detailed visual inspection of the cells for abnormalities that occur in the aging
process of the cell. In VLA battery visual inspections, some of the things that the inspector is
typically looking for on the plates are signs of sulfation of the plates, abnormal colors (which
are an indicator of sulfation or possible copper contamination) and abnormal conditions such as
cracked grids. The visual inspection could look for symptoms of hydration that would indicate
that the battery has been left in a completely discharged state for a prolonged period. Besides
looking at the plates for signs of aging, all internal connections, such as the bus bar connection
to each plate, and the connections to all posts of the battery need to be visually inspected for
abnormalities. In a complete visual inspection for the condition of the cell the cell plates,
separators and sediment space of each cell must be looked at for signs of deterioration. An
inspection of the station battery’s cell condition also includes looking at all terminal posts and
cell‐to‐cell electric connections to ensure they are corrosion free. The case of the battery
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containing the cell, or cells, must be inspected for cracks and electrolyte leaks through cracks
and the post seals.
This maintenance activity cannot be extended beyond the maximum maintenance interval of
Table 1‐4 by a Performance‐Based Maintenance Program (PBM) because of the electrochemical
aging process of the station battery, nor can there be any monitoring associated with it because
there must be a visual inspection involved in the activity. A remote visual inspection could
possibly be done, but its interval must be no greater than the maximum maintenance interval
of Table 1‐4.
Why is it necessary to verify the battery string can perform as manufactured? I
only care that the battery can trip the breaker, which means that the battery can
perform as designed. I oversize my batteries so that even if the battery cannot
perform as manufactured, it can still trip my breakers.
The fundamental answer to this question revolves around the concept of battery performance
“as designed” vs. battery performance “as manufactured.” The purpose of the various sections
of Table 1‐4 of this standard is to establish requirements for the Protection System owner to
maintain the batteries, to ensure they will operate the equipment when there is an incident
that requires dc power, and ensure the batteries will continue to provide adequate service until
at least the next maintenance interval. To meet these goals, the correct battery has to be
properly selected to meet the design parameters, and the battery has to deliver the power it
was manufactured to provide.
When testing batteries, it may be difficult to determine the original design (i.e., load profile) of
the dc system. This standard is not intended as a design document, and requirements relating
to design are, therefore, not included.
Where the dc load profile is known, the best way to determine if the system will operate as
designed is to conduct a service test on the battery. However, a service test alone might not
fully determine if the battery is healthy. A battery with 50% capacity may be able to pass a
service test, but the battery would be in a serious state of deterioration and could fail at some
point in the near future.
To ensure that the battery will meet the required load profile and continue to meet the load
profile until the next maintenance interval, the installed battery must be sized correctly (i.e., a
correct design), and it must be in a good state of health. Since the design of the dc system is
not within the scope of the standard, the only consistent and reliable method to ensure that
the battery is in a good state of health is to confirm that it can perform as manufactured. If the
battery can perform as manufactured and it has been designed properly, the system should
operate properly until the next maintenance interval.
How do I verify the battery string can perform as manufactured?
Optimally, actual battery performance should be verified against the manufacturer’s rating
curves. The best practice for evaluating battery performance is via a performance test.
However, due to both logistical and system reliability concerns, some Protection System
owners prefer other methods to determine if a battery can perform as manufactured. There
are several battery parameters that can be evaluated to determine if a battery can perform as
manufactured. Ohmic measurements and float current are two examples of parameters that
have been reported to assist in determining if a battery string can perform as manufactured.
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The evaluation of battery parameters in determining battery health is a complex issue, and is
not an exact science. This standard gives the user an opportunity to utilize other measured
parameters to determine if the battery can perform as manufactured. It is the responsibility of
the Protection System owner, however, to maintain a documented process that demonstrates
the chosen parameter(s) and associated methodology used to determine if the battery string
can perform as manufactured.
Whatever parameters are used to evaluate the battery (ohmic measurements, float current,
float voltages, temperature, specific gravity, performance test, or combination thereof), the
goal is to determine the value of the measurement (or the percentage change) at which the
battery fails to perform as manufactured, or the point where the battery is deteriorating so
rapidly that it will not perform as manufactured before the next maintenance interval.
This necessitates the need for establishing and documenting a baseline. A baseline may be
required of every individual cell, a particular battery installation, or a specific make, model, or
size of a cell. Given a consistent cell manufacturing process, it may be possible to establish a
baseline number for the cell (make/model/type) and, therefore, a subsequent baseline for
every installation would not be necessary. However, future installations of the same battery
types should be spot‐checked to ensure that your baseline remains applicable.
Consistent testing methods by trained personnel are essential. Moreover, it is essential that
these technicians utilize the same make/model of ohmic test equipment each time readings are
taken in order to establish a meaningful and accurate trendline against the established
baseline. The type of probe and its location (post, connector, etc) for the reading need to be the
same for each subsequent test. The room temperature should be recorded with the readings
for each test as well. Care should be taken to consider any factors that might lead a trending
program to become invalid.
Float current along with other measureable parameters can be used in lieu of or in concert with
ohmic measurement testing to measure the ability of a battery to perform as manufactured.
The key to using any of these measurement parameters is to establish a baseline and the point
where the reading indicates that the battery will not perform as manufactured.
The establishment of a baseline may be different for various types of cells and for different
types of installations. In some cases, it may be possible to obtain a baseline number from the
battery manufacturer, although it is much more likely that the baseline will have to be
established after the installation is complete. To some degree, the battery may still be
“forming” after installation; consequently, determining a stable baseline may not be possible
until several months after the battery has been in service.
The most important part of this process is to determine the point where the ohmic reading (or
other measured parameter(s)) indicates that the battery cannot perform as manufactured.
That point could be an absolute number, an absolute change, or a percentage change of an
established baseline.
Since there are no universally‐accepted repositories of this information, the Protection System
owner will have to determine the value/percentage where the battery cannot perform as
manufactured (heretofore referred to as a failed cell). This is the most difficult and important
part of the entire process.
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To determine the point where the battery fails to perform as manufactured, it is helpful to have
a history of a battery type, if the data includes the parameter(s) used to evaluate the battery's
ability to perform as manufactured against the actual demonstrated performance/capacity of a
battery/cell.
For example, when an ohmic reading has been recorded that the user suspects is indicating a
failed cell, a performance test of that cell (or string) should be conducted in order to
prove/quantify that the cell has failed. Through this process, the user needs to determine the
ohmic value at which the performance of the cell has dropped below 80% of the manufactured,
rated performance. It is likely that there may be a variation in ohmic readings that indicates a
failed cell (possibly significant). It is prudent to use the most conservative values to determine
the point at which the cell should be marked for replacement. Periodically, the user should
demonstrate that an “adequate” ohmic reading equates to an adequate battery performance
(>80% of capacity).
Similarly, acceptance criteria for "good" and "failed" cells should be established for other
parameters such as float current, specific gravity, etc., if used to determine the ability of a
battery to function as designed.
What happens if I change the make/model of ohmic test equipment after the
battery has been installed for a period of time?
If a user decides to switch testers, either voluntarily or because the equipment is not
supported/sold any longer, the user may have to establish a new base line and new parameters
that indicate when the battery no longer performs as manufactured. The user always has a
choice to perform a capacity test in lieu of establishing new parameters.
What are some of the differences between lead-acid and nickel-cadmium batteries?
There is a marked difference in the aging process of lead acid and nickel‐cadmium station
batteries. The difference in the aging process of these two types of batteries is chiefly due to
the electrochemical process of the battery type. Aging and eventual failure of lead acid
batteries is due to expansion and corrosion of the positive grid structure, loss of positive plate
active material, and loss of capacity caused by physical changes in the active material of the
positive plates. In contrast, the primary failure of nickel‐cadmium batteries is due to the
gradual linear aging of the active materials in the plates. The electrolyte of a nickel‐cadmium
battery only facilitates the chemical reaction (it functions only to transfer ions between the
positive and negative plates), but is not chemically altered during the process like the
electrolyte of a lead acid battery. A lead acid battery experiences continued corrosion of the
positive plate and grid structure throughout its operational life while a nickel‐cadmium battery
does not.
Changes to the properties of a lead acid battery when periodically measured and trended to a
baseline, can indicate aging of the grid structure, positive plate deterioration, or changes in the
active materials in the plate.
Because of the clear differences in the aging process of lead acid and nickel‐cadmium batteries,
there are no significantly measurable properties of the nickel‐cadmium battery that can be
measured at a periodic interval and trended to determine aging. For this reason, Table 1‐4(c)
(Protection System Station dc supply Using nickel‐cadmium [NiCad] Batteries) only specifies one
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minimum maintenance activity and associated maximum maintenance interval necessary to
verify that the station battery can perform as manufactured by evaluating cell/unit
measurements indicative of battery performance against the station battery baseline. This
maintenance activity is to conduct a performance or modified performance capacity test of the
entire battery bank.
Why in Table 1-4 of PRC-005-3 is there a maintenance activity to inspect the
structural intergrity of the battery rack?
The purpose of this inspection is to verify that the battery rack is correctly installed and has no
deterioration that could weaken its structural integrity.
Because the battery rack is specifically manufactured for the battery that is mounted on it,
weakening of its structural members by rust or corrosion can physically jeopardize the battery.
What is required to comply with the “Unintentional dc Grounds” requirement?
In most cases, the first ground that appears on a battery is not a problem. It is the
unintentional ground that appears on the opposite pole that becomes problematic. Even then
many systems are designed to operate favorably under some unintentional DC ground
situations. It is up to the owner of the Protection System to determine if corrective actions are
needed on detected unintentional DC grounds. The standard merely requires that a check be
made for the existence of Unintentional DC Grounds. Obviously, a “check‐off” of some sort will
have to be devised by the inspecting entity to document that a check is routinely done for
Unintentional DC Grounds because of the possible consequences to the Protection System.
Where the standard refers to “all cells,” is it sufficient to have a documentation
method that refers to “all cells,” or do we need to have separate documentation for
every cell? For example, do I need 60 individual documented check-offs for good
electrolyte level, or would a single check-off per bank be sufficient?
A single check‐off per battery bank is sufficient for documentation, as long as the single check‐
off attests to checking all cells/units.
Does this standard refer to Station batteries or all batteries; for example,
Communications Site Batteries?
This standard refers to Station Batteries. The drafting team does not believe that the scope of
this standard refers to communications sites. The batteries covered under PRC‐005‐3 are the
batteries that supply the trip current to the trip coils of the interrupting devices that are a part
of the Protection System. The SDT believes that a loss of power to the communications
systems at a remote site would cause the communications systems associated with protective
relays to alarm at the substation. At this point, the corrective actions can be initiated.
What are cell/unit internal ohmic measurements?
With the introduction of Valve‐Regulated Lead‐Acid (VRLA) batteries to station dc supplies in
the 1980’s several of the standard maintenance tools that are used on Vented Lead‐Acid (VLA)
batteries were unable to be used on this new type of lead‐acid battery to determine its state of
health. The only tools that were available to give indication of the health of these new VRLA
batteries were voltage readings of the total battery voltage, the voltage of the individual cells
and periodic discharge tests.
In the search for a tool for determining the health of a VRLA battery several manufacturers
studied the electrical model of a lead acid battery’s current path through its cell. The overall
battery current path consists of resistance and inductive and capacitive reactance. The
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inductive reactance in the current path through the battery is so minuscule when compared to
the huge capacitive reactance of the cells that it is often ignored in most circuit models of the
battery cell. Taking the basic model of a battery cell manufacturers of battery test equipment
have developed and marketed testing devices to take measurements of the current path to
detect degradation in the internal path through the cell.
In the battery industry, these various types of measurements are referred to as ohmic
measurements. Terms used by the industry to describe ohmic measurements are ac
conductance, ac impedance, and dc resistance. They are defined by the test equipment
providers and IEEE and refer to the method of taking ohmic measurements of a lead acid
battery. For example, in one manufacturer’s ac conductance equipment measurements are
taken by applying a voltage of a known frequency and amplitude across a cell or battery unit
and observing the ac current flow it produces in response to the voltage. A manufacturer of an
ac impedance meter measures ac current of a known frequency and amplitude that is passed
through the whole battery string and determines the impedances of each cell or unit by
measuring the resultant ac voltage drop across them. On the other hand, dc resistance of a cell
is measured by a third manufacturer’s equipment by applying a dc load across the cell or unit
and measuring the step change in both the voltage and current to calculate the internal dc
resistance of the cell or unit.
It is important to note that because of the rapid development of the market for ohmic
measurement devices, there were no standards developed or used to mandate the test signals
used in making ohmic measurements. Manufacturers using proprietary methods and applying
different frequencies and magnitudes for their signals have developed a diversity of
measurement devices. This diversity in test signals coupled with the three different types of
ohmic measurements techniques (impedance conductance and resistance) make it impossible
to always get the same ohmic measurement for a cell with different ohmic measurement
devices. However, IEEE has recognized the great value for choosing one device for ohmic
measurement, no matter who makes it or the method to calculate the ohmic measurement.
The only caution given by IEEE and the battery manufacturers is that when trending the cells of
a lead acid station battery consistent ohmic measurement devices should be used to establish
the baseline measurement and to trend the battery set for its entire life.
For VRLA batteries both IEEE Standard 1188 (Maintenance, Testing and Replacement of VRLA
Batteries) and IEEE Standard 1187 (Installation Design and Installation of VRLA Batteries)
recognize the importance of the maintenance activity of establishing a baseline for “cell/unit
internal ohmic measurements (impedance, conductance and resistance)” and trending them at
frequent intervals over the life of the battery. There are extensive discussions about the need
for taking these measurements in these standards. IEEE Standard 1188 requires taking internal
ohmic values as described in Annex C4 during regular inspections of the station battery. For
VRLA batteries IEEE Standard 1188 in talking about the necessity of establishing a baseline and
trending it over time says, “…depending on the degree of change a performance test, cell
replacement or other corrective action may be necessary…” (IEEE std 1188‐2005, C.4 page 18).
For VLA batteries IEEE Standard 484 (Installation of VLA batteries) gives several guidelines
about establishing baseline measurements on newly installed lead acid stationary batteries.
The standard also discusses the need to look for significant changes in the ohmic
measurements, the caution that measurement data will differ with each type of model of
instrument used, and lists a number of factors that affect ohmic measurements.
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At the beginning of the 21st century, EPRI conducted a series of extensive studies to determine
the relationship of internal ohmic measurements to the capacity of a lead acid battery cell. The
studies indicated that internal ohmic measurements were in fact a good indicator of a lead acid
battery cell’s capacity, but because users often were only interested in the total station battery
capacity and the technology does not precisely predict overall battery capacity, if a user only
needs “an accurate measure of the overall battery capacity,” they should “perform a battery
capacity test.”
Prior to the EPRI studies some large and small companies which owned and maintained station
dc supplies in NERC Protection Systems developed maintenance programs where trending of
ohmic measurements of cells/units of the station’s battery became the maintenance activity for
determining if the station battery could perform as manufactured. By evaluation of the
trending of the ohmic measurements over time, the owner could track the performance of the
individual components of the station battery and determine if a total station battery or
components of it required capacity testing, removal, replacement or in many instances
replacement of the entire station battery. By taking this condition based approach these
owners have eliminated having to perform capacity testing at prescribed intervals to determine
if a battery needs to be replaced and are still able to effectively determine if a station battery
can perform as manufactured.
My VRLA batteries have multiple-cells within an individual battery jar (or unit); how
am I expected to comply with the cell-to-cell ohmic measurement requirements on
these units that I cannot get to?
Measurement of cell/unit (not all batteries allow access to “individual cells” some “units” or jars
may have multiple cells within a jar) internal ohmic values of all types of lead acid batteries
where the cells of the battery are not visible is a station dc supply maintenance activity in Table
1‐4. In cases where individual cells in a multi‐cell unit are inaccessible, an ohmic measurement
of the entire unit may be made.
I have a concern about my batteries being used to support additional auxiliary loads
beyond my protection control systems in a generation station. Is ohmic
measurement testing sufficient for my needs?
While this standard is focused on addressing requirements for Protection Systems, if batteries
are used to service other load requirements beyond that of Protection Systems (e.g. pumps,
valves, inverter loads), the functional entity may consider additional testing to confirm that the
capacity of the battery is sufficient to support all loads.
Why verify voltage?
There are two required maintenance activities associated with verification of dc voltages in
Table 1‐4. These two required activities are to verify station dc supply voltage and float voltage
of the battery charger, and have different maximum maintenance intervals. Both of these
voltage verification requirements relate directly to the battery charger maintenance.
The verification of the dc supply voltage is simply an observation of battery voltage to prove
that the charger has not been lost or is not malfunctioning; a reading taken from the battery
charger panel meter or even SCADA values of the dc voltage could be some of the ways that
one could satisfy the requirements. Low battery voltage below float voltage indicates that the
battery may be on discharge and, if not corrected, the station battery could discharge down to
some extremely low value that will not operate the Protection System. High voltage, close to or
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above the maximum allowable dc voltage for equipment connected to the station dc supply
indicates the battery charger may be malfunctioning by producing high dc voltage levels on the
Protection System. If corrective actions are not taken to bring the high voltage down, the dc
power supplies and other electronic devices connected to the station dc supply may be
damaged. The maintenance activity of verifying the float voltage of the battery charger is not
to prove that a charger is lost or producing high voltages on the station dc supply, but rather to
prove that the charger is properly floating the battery within the proper voltage limits. As
above, there are many ways that this requirement can be met.
Why check for the electrolyte level?
In vented lead‐acid (VLA) and nickel‐cadmium (NiCad) batteries the visible electrolyte level
must be checked as one of the required maintenance activities that must be performed at an
interval that is equal to or less than the maximum maintenance interval of Table 1‐4. Because
the electrolyte level in valve‐regulated lead‐acid (VRLA) batteries cannot be observed, there is
no maintenance activity listed in Table 1‐4 of the standard for checking the electrolyte level.
Low electrolyte level of any cell of a VLA or NiCad station battery is a condition requiring
correction. Typically, the electrolyte level should be returned to an acceptable level for both
types of batteries (VLA and NiCad) by adding distilled or other approved‐quality water to the
cell.
Often people confuse the interval for watering all cells required due to evaporation of the
electrolyte in the station battery cells with the maximum maintenance interval required to
check the electrolyte level. In many of the modern station batteries, the jar containing the
electrolyte is so large with the band between the high and low electrolyte level so wide that
normal evaporation which would require periodic watering of all cells takes several years to
occur. However, because loss of electrolyte due to cracks in the jar, overcharging of the station
battery, or other unforeseen events can cause rapid loss of electrolyte; the shorter maximum
maintenance intervals for checking the electrolyte level are required. A low level of electrolyte
in a VLA battery cell which exposes the tops of the plates can cause the exposed portion of the
plates to accelerated sulfation resulting in loss of cell capacity. Also, in a VLA battery where the
electrolyte level goes below the end of the cell withdrawal tube or filling funnel, gasses can exit
the cell by the tube instead of the flame arrester and present an explosion hazard.
What are the parameters that can be evaluated in Tables 1-4(a) and 1-4(b)?
The most common parameter that is periodically trended and evaluated by industry today to
verify that the station battery can perform as manufactured is internal ohmic cell/unit
measurements.
In the mid 1990s, several large and small utilities began developing maintenance and testing
programs for Protection System station batteries using a condition based maintenance
approach of trending internal ohmic measurements to each station battery cell’s baseline
value. Battery owners use the data collected from this maintenance activity to determine (1)
when a station battery requires a capacity test (instead of performing a capacity test on a
predetermined, prescribed interval), (2) when an individual cell or battery unit should be
replaced, or (3) based on the analysis of the trended data, if the station battery should be
replaced without performing a capacity test.
Other examples of measurable parameters that can be periodically trended and evaluated for
lead acid batteries are cell voltage, float current, connection resistance. However, periodically
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trending and evaluating cell/unit Ohmic measurements are the most common battery/cell
parameters that are evaluated by industry to verify a lead acid battery string can perform as
manufactured.
Why does it appear that there are two maintenance activities in Table 1-4(b) (for
VRLA batteries) that appear to be the same activity and have the same maximum
maintenance interval?
There are two different and distinct reasons for doing almost the same maintenance activity at
the same interval for valve‐regulated lead‐acid (VRLA) batteries. The first similar activity for
VRLA batteries (Table 1‐4(b)) that has the same maximum maintenance interval is to “measure
battery cell/unit internal ohmic values.” Part of the reason for this activity is because the visual
inspection of the cell condition is unavailable for VRLA batteries. Besides the requirement to
measure the internal ohmic measurements of VRLA batteries to determine the internal health
of the cell, the maximum maintenance interval for this activity is significantly shorter than the
interval for vented lead‐acid (VLA) due to some unique failure modes for VRLA batteries. Some
of the potential problems that VRLA batteries are susceptible to that do not affect VLA batteries
are thermal runaway, cell dry‐out, and cell reversal when one cell has a very low capacity.
The other similar activity listed in Table 1‐4(b) is “…verify that the station battery can perform
as manufactured by evaluating the measured cell/unit measurements indicative of battery
performance (e.g. internal ohmic values) against the station battery baseline.” This activity
allows an owner the option to choose between this activity with its much shorter maximum
maintenance interval or the longer maximum maintenance interval for the maintenance activity
to “Verify that the station battery can perform as manufactured by conducting a performance
or modified performance capacity test of the entire battery bank.”
For VRLA batteries, there are two drivers for internal ohmic readings. The first driver is for a
means to trend battery life. Trending against the baseline of VRLA cells in a battery string is
essential to determine the approximate state of health of the battery. Ohmic measurement
testing may be used as the mechanism for measuring the battery cells. If all the cells in the
string exhibit a consistent trend line and that trend line has not risen above a specific deviation
(e.g. 30%) over baseline for impedance tests or below baseline for conductance tests, then a
judgment can be made that the battery is still in a reasonably good state of health and able to
‘perform as manufactured.’ It is essential that the specific deviation mentioned above is based
on data (test or otherwise) that correlates the ohmic readings for a specific battery/tester
combination to the health of the battery. This is the intent of the “perform as manufactured
six‐month test” at Row 4 on Table 1‐4b.
The second big driver is VRLA batteries tendency for thermal runaway. This is the intent of the
“thermal runaway test” at Row 2 on Table 1‐4b. In order to detect a cell in thermal runaway,
you need not necessarily have a formal trending program. When a single cell/unit changes
significantly or significantly varies from the other cells (e.g. a doubling of resistance/impedance
or a 50% decrease in conductance), there is a high probability that the cell/unit/string needs to
be replaced as soon as possible. In other words, if the battery is 10 years old and all the cells
have approached a significant change in ohmic values over baseline, then you have a battery
which is approaching end of life. You need to get ready to buy a new battery, but you do not
have to worry about an impending catastrophic failure. On the other hand, if the battery is five
years old and you have one cell that has a markedly different ohmic reading than all the other
cells, then you need to be worried that this cell is susceptible to thermal runaway. If the float
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(charging) current has risen significantly and the ohmic measurement has increased/decreased
as described above then concern of catastrophic failure should trigger attention for corrective
action.
If an entity elects to use a capacity test rather than a cell ohmic value trending program, this
does not eliminate the need to be concerned about thermal runaway – the entity still needs to
do the six‐month readings and look for cells which are outliers in the string but they need not
trend results against the factory/as new baseline. Some entities will not mind the extra
administrative burden of having the ongoing trending program against baseline ‐ others would
rather just do the capacity test and not have to trend the data against baseline. Nonetheless,
all entities must look for ohmic outliers on a six‐month basis.
It is possible to accomplish both tasks listed (trend testing for capability and testing for thermal
runaway candidates) with the very same ohmic test. It becomes an analysis exercise of
watching the trend from baselines and watching for the oblique cell measurement.
In table 1-4(f) (Exclusions for Protection System Station dc Supply Monitoring
Devices and Systems), must all component attributes listed in the table be met
before an exclusion can be granted for a maintenance activity?
Table 1‐4(f) was created by the drafting team to allow Protection System dc supply owners to
obtain exclusions from periodic maintenance activities by using monitoring devices. The basis
of the exclusions granted in the table is that the monitoring devices must incorporate the
monitoring capability of microprocessor based components which perform continuous self‐
monitoring. For failure of the microprocessor device used in dc supply monitoring, the self
checking routine in the microprocessor must generate an alarm which will be reported within
24 hours of device failure to a location where corrective action can be initiated.
Table 1‐4(f) lists 8 component attributes along with a specific periodic maintenance activity
associated with each of the 8 attributes listed. If an owner of a station dc supply wants to be
excluded from periodically performing one of the 8 maintenance activities listed in table 1‐4(f),
the owner must have evidence that the monitoring and alarming component attributes
associated with the excluded maintenance activity are met by the self checking microprocessor
based device with the specific component attribute listed in the table 1‐4(f).
For example if an owner of a VLA station battery does not want to “verify station dc supply
voltage” every “4 calendar months” (see table 1‐4(a)), the owner can install a monitoring and
alarming device “with high and low voltage monitoring and alarming of the battery charger
voltage to detect charger overvoltage and charger failure” and “no periodic verification of
station dc supply voltage is required” (see table 1‐4(f) first row). However, if for the same
Protection System discussed above, the owner does not install “electrolyte level monitoring
and alarming in every cell” and “unintentional dc ground monitoring and alarming” (see second
and third rows of table 1‐4(f)), the owner will have to “inspect electrolyte level and for
unintentional grounds” every “4 calendar months” (see table 1‐4(a)).
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15.5 Associated communications equipment (Table 1-2)
The equipment used for tripping in a communications‐assisted trip scheme is a vital piece of the
trip circuit. Remote action causing a local trip can be thought of as another parallel trip path to
the trip coil that must be tested. Besides the trip output and wiring to the trip coil(s), there is
also a communications medium that must be maintained. Newer technologies now exist that
achieve communications‐assisted tripping without the conventional wiring practices of older
technology. For example, older technologies may have included Frequency Shift Key methods.
This technology requires that guard and trip levels be maintained. The actual tripping path(s) to
the trip coil(s) may be tested as a parallel trip path within the dc control circuitry tests.
Emerging technologies transfer digital information over a variety of carrier mediums that are
then interpreted locally as trip signals. The requirements apply to the communicated signal
needed for the proper operation of the protective relay trip logic or scheme. Therefore, this
standard is applied to equipment used to convey both trip signals (permissive or direct) and
block signals.
It was the intent of this standard to require that a test be performed on any communications‐
assisted trip scheme, regardless of the vintage of technology. The essential element is that the
tripping (or blocking) occurs locally when the remote action has been asserted; or that the
tripping (or blocking) occurs remotely when the local action is asserted. Note that the required
testing can still be done within the concept of testing by overlapping segments. Associated
communications equipment can be (but is not limited to) testing at other times and different
frequencies as the protective relays, the individual trip paths and the affected circuit
interrupting devices.
Some newer installations utilize digital signals over fiber‐optics from the protective relays in the
control house to the circuit interrupting device in the yard. This method of tripping the circuit
breaker, even though it might be considered communications, must be maintained per the dc
control circuitry maintenance requirements.
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15.5.1 Frequently Asked Questions:
What are some examples of mechanisms to check communications equipment
functioning?
For unmonitored Protection Systems, various types of communications systems will have
different facilities for on‐site integrity checking to be performed at least every four months
during a substation visit. Some examples are, but not limited to:
On‐off power‐line carrier systems can be checked by performing a manual carrier keying
test between the line terminals, or carrier check‐back test from one terminal.
Systems which use frequency‐shift communications with a continuous guard signal (over
a telephone circuit, analog microwave system, etc.) can be checked by observing for a
loss‐of‐guard indication or alarm. For frequency‐shift power‐line carrier systems, the
guard signal level meter can also be checked.
Hard‐wired pilot wire line Protection Systems typically have pilot‐wire monitoring relays
that give an alarm indication for a pilot wire ground or open pilot wire circuit loop.
Digital communications systems typically have a data reception indicator or data error
indicator (based on loss of signal, bit error rate, or frame error checking).
For monitored Protection Systems, various types of communications systems will have different
facilities for monitoring the presence of the communications channel, and activating alarms
that can be monitored remotely. Some examples are, but not limited to:
On‐off power‐line carrier systems can be shown to be operational by automated
periodic power‐line carrier check‐back tests with remote alarming of failures.
Systems which use a frequency‐shift communications with a continuous guard signal
(over a telephone circuit, analog microwave system, etc.) can be remotely monitored
with a loss‐of‐guard alarm or low signal level alarm.
Hard‐wired pilot wire line Protection Systems can be monitored by remote alarming of
pilot‐wire monitoring relays.
Digital communications systems can activate remotely monitored alarms for data
reception loss or data error indications.
Systems can be queried for the data error rates.
For the highest degree of monitoring of Protection Systems, the communications system must
monitor all aspects of the performance and quality of the channel that show it meets the design
performance criteria, including monitoring of the channel interface to protective relays.
In many communications systems signal quality measurements, including signal‐to‐noise
ratio, received signal level, reflected transmitter power or standing wave ratio,
propagation delay, and data error rates are compared to alarm limits. These alarms are
connected for remote monitoring.
Alarms for inadequate performance are remotely monitored at all times, and the alarm
communications system to the remote monitoring site must itself be continuously
monitored to assure that the actual alarm status at the communications equipment
location is continuously being reflected at the remote monitoring site.
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What is needed for the four-month inspection of communications-assisted trip
scheme equipment?
The four‐month inspection applies to unmonitored equipment. An example of compliance with
this requirement might be, but is not limited to:
With each site visit, check that the equipment is free from alarms; check any metered signal
levels, and that power is still applied. While this might be explicit for a particular type of
equipment (i.e., FSK equipment), the concept should be that the entity verify that the
communications equipment that is used in a Protection System is operable through a cursory
inspection and site visit. This site visit can be eliminated on this particular example if the FSK
equipment had a monitored alarm on Loss of Guard. Blocking carrier systems with auto
checkbacks will present an alarm when the channel fails allowing a visual indication. With no
auto checkback, the channel integrity will need to be verified by a manual checkback or a two
ended signal check. This check could also be eliminated by bring the auto checkback failure
alarm to the monitored central location.
Does a fiber optic I/O scheme used for breaker tripping or control within a station,
for example - transmitting a trip signal or control logic between the control house
and the breaker control cabinet, constitute a communications system?
This equipment is presently classified as being part of the Protection System control circuitry
and tested per the portions of Table 1 applicable to “Protection System Control Circuitry”,
rather than those portions of the table applicable to communications equipment.
What is meant by “Channel” and “Communications Systems” in Table 1-2?
The transmission of logic or data from a relay in one station to a relay in another station for use
in a pilot relay scheme will require a communications system of some sort. Typical relay
communications systems use fiber optics, leased audio channels, power line carrier, and
microwave. The overall communications system includes the channel and the associated
communications equipment.
This standard refers to the “channel” as the medium between the transmitters and receivers in
the relay panels such as a leased audio or digital communications circuit, power line and power
line carrier auxiliary equipment, and fiber. The dividing line between the channel and the
associated communications equipment is different for each type of media.
Examples of the Channel:
Power Line Carrier (PLC) ‐ The PLC channel starts and ends at the PLC transmitter and
receiver output unless there is an internal hybrid. The channel includes the external
hybrids, tuners, wave traps and the power line itself.
Microwave –The channel includes the microwave multiplexers, radios, antennae and
associated auxiliary equipment. The audio tone and digital transmitters and receivers in
the relay panel are the associated communications equipment.
Digital/Audio Circuit – The channel includes the equipment within and between the
substations. The associated communications equipment includes the relay panel
transmitters and receivers and the interface equipment in the relays.
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Fiber Optic – The channel starts at the fiber optic connectors on the fiber distribution
panel at the local station and goes to the fiber optic distribution panel at the remote
substation. The jumpers that connect the relaying equipment to the fiber distribution
panel and any optical‐electrical signal format converters are the associated
communications equipment
Figure 1‐2, A‐1 and A‐2 at the end of this document show good examples of the
communications channel and the associated communications equipment.
In Table 1-2, the Maintenance Activities section of the Protection System
Communications Equipment and Channels refers to the quality of the channel
meeting “performance criteria.” What is meant by performance criteria?
Protection System communications channels must have a means of determining if the channel
and communications equipment is operating normally. If the channel is not operating normally,
an alarm will be indicated. For unmonitored systems, this alarm will probably be on the panel.
For monitored systems, the alarm will be transmitted to a remote location.
Each entity will have established a nominal performance level for each Protection System
communications channel that is consistent with proper functioning of the Protection System. If
that level of nominal performance is not being met, the system will go into alarm. Following
are some examples of Protection System communications channel performance measuring:
For direct transfer trip using a frequency shift power line carrier channel, a guard level
monitor is part of the equipment. A normal receive level is established when the system
is calibrated and if the signal level drops below an established level, the system will
indicate an alarm.
An on‐off blocking signal over power line carrier is used for directional comparison
blocking schemes on transmission lines. During a Fault, block logic is sent to the remote
relays by turning on a local transmitter and sending the signal over the power line to a
receiver at the remote end. This signal is normally off so continuous levels cannot be
checked. These schemes use check‐back testing to determine channel performance. A
predetermined signal sequence is sent to the remote end and the remote end decodes
this signal and sends a signal sequence back. If the sending end receives the correct
information from the remote terminal, the test passes and no alarm is indicated. Full
power and reduced power tests are typically run. Power levels for these tests are
determined at the time of calibration.
Pilot wire relay systems use a hardwire communications circuit to communicate
between the local and remote ends of the protective zone. This circuit is monitored by
circulating a dc current between the relay systems. A typical level may be 1 mA. If the
level drops below the setting of the alarm monitor, the system will indicate an alarm.
Modern digital relay systems use data communications to transmit relay information to
the remote end relays. An example of this is a line current differential scheme
commonly used on transmission lines. The protective relays communicate current
magnitude and phase information over the communications path to determine if the
Fault is located in the protective zone. Quantities such as digital packet loss, bit error
rate and channel delay are monitored to determine the quality of the channel. These
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limits are determined and set during relay commissioning. Once set, any channel quality
problems that fall outside the set levels will indicate an alarm.
The previous examples show how some protective relay communications channels can be
monitored and how the channel performance can be compared to performance criteria
established by the entity. This standard does not state what the performance criteria will be; it
just requires that the entity establish nominal criteria so Protection System channel monitoring
can be performed.
How is the performance criteria of Protection System communications equipment
involved in the maintenance program?
An entity determines the acceptable performance criteria, depending on the technology
implemented. If the communications channel performance of a Protection System varies from
the pre‐determined performance criteria for that system, then these results should be
investigated and resolved.
How do I verify the A/D converters of microprocessor-based relays?
There are a variety of ways to do this. Two examples would be: using values gathered via data
communications and automatically comparing these values with values from other sources, or
using groupings of other measurements (such as vector summation of bus feeder currents) for
comparison. Many other methods are possible.
15.6 Alarms (Table 2)
In addition to the tables of maintenance for the components of a Protection System, there is an
additional table added for alarms. This additional table was added for clarity. This enabled the
common alarm attributes to be consolidated into a single spot, and, thus, make it easier to read
the Tables 1‐1 through 1‐5, Table 3, and Table 4. The alarms need to arrive at a site wherein a
corrective action can be initiated. This could be a control room, operations center, etc. The
alarming mechanism can be a standard alarming system or an auto‐polling system; the only
requirement is that the alarm be brought to the action‐site within 24 hours. This effectively
makes manned‐stations equivalent to monitored stations. The alarm of a monitored point (for
example a monitored trip path with a lamp) in a manned‐station now makes that monitored
point eligible for monitored status. Obviously, these same rules apply to a non‐manned‐
station, which is that if the monitored point has an alarm that is auto‐reported to the
operations center (for example) within 24 hours, then it too is considered monitored.
15.6.1 Frequently Asked Questions:
Why are there activities defined for varying degrees of monitoring a Protection
System component when that level of technology may not yet be available?
There may already be some equipment available that is capable of meeting the highest levels of
monitoring criteria listed in the Tables. However, even if there is no equipment available today
that can meet this level of monitoring the standard establishes the necessary requirements for
when such equipment becomes available. By creating a roadmap for development, this
provision makes the standard technology neutral. The Standard Drafting Team wants to avoid
the need to revise the standard in a few years to accommodate technology advances that may
be coming to the industry.
Does a fail-safe “form b” contact that is alarmed to a 24/7 operation center classify
as an alarm path with monitoring?
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If the fail‐safe “form‐b” contact that is alarmed to a 24/7 operation center causes the alarm to
activate for failure of any portion of the alarming path from the alarm origin to the 24/7
operations center, then this can be classified as an alarm path with monitoring.
15.7 Distributed UFLS and Distributed UVLS Systems (Table 3)
Distributed UFLS and distributed UVLS systems have their maintenance activities documented
in Table 3 due to their distributed nature allowing reduced maintenance activities and extended
maximum maintenance intervals. Relays have the same maintenance activities and intervals as
Table 1‐1. Voltage and current‐sensing devices have the same maintenance activity and
interval as Table 1‐3. DC systems need only have their voltage read at the relay every 12 years.
Control circuits have the following maintenance activities every 12 years:
Verify the trip path between the relay and lock‐out and/or auxiliary tripping device(s).
Verify operation of any lock‐out and/or auxiliary tripping device(s) used in the trip
circuit.
No verification of trip path required between the lock‐out (and/or auxiliary tripping
device) and the non‐BES interrupting device.
No verification of trip path required between the relay and trip coil for circuits that have
no lock‐out and/or auxiliary tripping device(s).
No verification of trip coil required.
No maintenance activity is required for associated communication systems for distributed UFLS
and distributed UVLS schemes.
Non‐BES interrupting devices that participate in a distributed UFLS or distributed UVLS scheme
are excluded from the tripping requirement, and part of the control circuit test requirement;
however, the part of the trip path control circuitry between the Load‐Shed relay and lock‐out or
auxiliary tripping relay must be tested at least once every 12 years. In the case where there is
no lock‐out or auxiliary tripping relay used in a distributed UFLS or UVLS scheme which is not
part of the BES, there is no control circuit test requirement. There are many circuit interrupting
devices in the distribution system that will be operating for any given under‐frequency event
that requires tripping for that event. A failure in the tripping action of a single distributed
system circuit breaker (or non‐BES equipment interruption device) will be far less significant
than, for example, any single transmission Protection System failure, such as a failure of a bus
differential lock‐out relay. While many failures of these distributed system circuit breakers (or
non‐BES equipment interruption device) could add up to be significant, it is also believed that
many circuit breakers are operated often on just Fault clearing duty; and, therefore, these
circuit breakers are operated at least as frequently as any requirements that appear in this
standard.
There are times when a Protection System component will be used on a BES device, as well as a
non‐BES device, such as a battery bank that serves both a BES circuit breaker and a non‐BES
interrupting device used for UFLS. In such a case, the battery bank (or other Protection System
component) will be subject to the Tables of the standard because it is used for the BES.
15.7.1 Frequently Asked Questions:
The standard reaches further into the distribution system than we would like for
UFLS and UVLS
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While UFLS and UVLS equipment are located on the distribution network, their job is to protect
the Bulk Electric System. This is not beyond the scope of NERC’s 215 authority.
FPA section 215(a) definitions section defines bulk power system as: “(A) facilities and control
Systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof).” That definition, then, is limited by a later statement which adds the term
bulk power system “…does not include facilities used in the local distribution of electric
energy.” Also, Section 215 also covers users, owners, and operators of bulk power Facilities.
UFLS and UVLS (when the UVLS is installed to prevent system voltage collapse or voltage
instability for BES reliability) are not “used in the local distribution of electric energy,” despite
their location on local distribution networks. Further, if UFLS/UVLS Facilities were not covered
by the reliability standards, then in order to protect the integrity of the BES during under‐
frequency or under‐voltage events, that Load would have to be shed at the Transmission bus to
ensure the Load‐generation balance and voltage stability is maintained on the BES.
15.8 Automatic Reclosing (Table 4)
Please see the document referenced in Section F of PRC‐005‐3, “Considerations for
Maintenance and Testing of Autoreclosing Schemes — November 2012”, for a discussion of
Automatic Reclosing as addressed in PRC‐005‐3.
15.8.1 Frequently-asked Questions
Automatic Reclosing is a control, not a protective function; why then is Automatic
Reclosing maintenance included in the Protection System Maintenance Program
(PSMP)?
Automatic Reclosing is a control function. The standard’s title ‘Protection System and
Automatic Reclosing Maintenance’ clearly distinguishes (separates) the Automatic Reclosing
from the Protection System. Automatic Reclosing is included in the PSMP because it is a more
pragmatic approach as compared to creating a parallel and essentially identical ‘Control System
Maintenance Program’ for the two Automatic Reclosing component types.
Our maintenance practice consists of initiating the Automatic Reclosing relay and
confirming the breaker closes properly and the close signal is released. This practice
verifies the control circuitry associated with Automatic Reclosing. Do you agree?”
The described task partially verifies the control circuit maintenance activity. To meet the
control circuit maintenance activity, responsible entities need to verify, upon initiation, that the
reclosing relay does not issue a premature closing command. As noted on page 12 of the
SAMS/SPCS report, the concern being addressed within the standard is premature
autoreclosing that has the potential to cause generating unit or plant instability. Reclosing
applications have many variations, responsible entities will need to verify the applicability of
associated supervisorsupervision/conditional logic and the reclosing relay operation; then verify
the conditional logic or that the reclosing relay performs in a manner that does not result in a
premature closing command being issued.
Some examples of conditions which can result in a premature closing command are: an
improper supervision or conditional logic input which provides a false state and allows the
reclosing relay to issue an improper close command based on incorrect conditions (i.e. voltage
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
98
supervision, equipment status, sync window verification); timers utilized for closing actuation
or reclosing arming/disarming circuitry which could allow the reclosing relay to issue an
improper close command; a reclosing relay output contact failure which could result in a made‐
up‐close condition / failure‐to‐release condition.
Why was a close-in three phase fault present for twice the normal clearing time
chosen for the Automatic Reclosing exclusion? It exceeds TPL requirements and
ignores the breaker closing time in a trip-close-trip sequence, thus making the
exclusion harder to attain.
This condition represents a situation where a close signal is issued with no time delay or with
less time delay than is intended, such as if a reclosing contact is welded closed. This failure
mode can result in a minimum trip‐close‐trip sequence with the two faults cleared in primary
protection operating time, and the open time between faults equal to the breaker closing cycle
time. The sequence for this failure mode results in system impact equivalent to a high‐speed
autoreclosing sequence with no delay added in the autoreclosing logic. It represents a failure
mode which must be avoided because it exceeds TPL requirements.
Do we have to test the various breaker closing circuit interlocks and controls such
as anti-pump?
These components are not specifically addressed within Table 4, and need not be individually
tested. They are indirectly verified by performing the Automatic Reclosing control circuitry
verification as established in Table 4.
For Automatic Reclosing that is not part of an SPS, do we have to close the circuit
breaker periodically?
No. For this application, you need only to verify that the Automatic Reclosing, upon initiation,
does not issue a premature closing command. This activity is concerned only with assuring that
a premature close does not occur, and cause generating plant instability.
For Automatic Reclosing that is part of an SPS, do we have to close the circuit
breaker periodically?
Yes. In this application, successful closing is a necessary portion of the SPS, and must be
verified.
15.9 Examples of Evidence of Compliance
To comply with the requirements of this standard, an entity will have to document and save
evidence. The evidence can be of many different forms. The Standard Drafting Team recognizes
that there are concurrent evidence requirements of other NERC standards that could, at times,
fulfill evidence requirements of this standard.
15.9.1 Frequently Asked Questions:
What forms of evidence are acceptable?
Acceptable forms of evidence, as relevant for the requirement being documented include, but
are not limited to:
Process documents or plans
Data (such as relay settings sheets, photos, SCADA, and test records)
Database lists, records and/or screen shots that demonstrate compliance information
Prints, diagrams and/or schematics
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
99
Maintenance records
Logs (operator, substation, and other types of log)
Inspection forms
Mail, memos, or email proving the required information was exchanged, coordinated,
submitted or received
Check‐off forms (paper or electronic)
Any record that demonstrates that the maintenance activity was known, accounted for,
and/or performed.
If I replace a failed Protection System component with another component, what
testing do I need to perform on the new component?
In order to reset the Table 1 maintenance interval for the replacement component, all relevant
Table 1 activities for the component should be performed.
I have evidence to show compliance for PRC-016 (“Special Protection System
Misoperation”). Can I also use it to show compliance for this Standard, PRC-005-3?
Maintaining evidence for operation of Special Protection Systems could concurrently be utilized
as proof of the operation of the associated trip coil (provided one can be certain of the trip coil
involved). Thus, the reporting requirements that one may have to do for the Misoperation of a
Special Protection Scheme under PRC‐016 could work for the activity tracking requirements
under this PRC‐005‐3.
I maintain Disturbance records which show Protection System operations. Can I
use these records to show compliance?
These records can be concurrently utilized as dc trip path verifications, to the degree that they
demonstrate the proper function of that dc trip path.
I maintain test reports on some of my Protection System components. Can I use
these test reports to show that I have verified a maintenance activity?
Yes.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
100
References
1. Protection System Maintenance: A Technical Reference. Prepared by the System Protection
and Controls Task Force of the NERC Planning Committee. Dated September 13, 2007.
2. “Predicating The Optimum Routine test Interval For Protection Relays,” by J. J.
Kumm, M.S. Weber, D. Hou, and E. O. Schweitzer, III, IEEE Transactions on Power
Delivery, Vol. 10, No. 2, April 1995.
3. “Transmission Relay System Performance Comparison For 2000, 2001, 2002, 2003,
2004 and 2005,” Working Group I17 of Power System Relaying Committee of IEEE
Power Engineering Society, May 2006.
4. “A Survey of Relaying Test Practices,” Special Report by WG I11 of Power System
Relaying Committee of IEEE Power Engineering Society, September 16, 1999.
5. “Transmission Protective Relay System Performance Measuring Methodology,”
Working Group I3 of Power System Relaying Committee of IEEE Power Engineering
Society, January 2002.
6. “Processes, Issues, Trends and Quality Control of Relay Settings,” Working Group C3
of Power System Relaying Committee of IEEE Power Engineering Society, December
2006.
7. “Proposed Statistical Performance Measures for Microprocessor‐Based
Transmission‐Line Protective Relays, Part I ‐ Explanation of the Statistics, and Part II ‐
Collection and Uses of Data,” Working Group D5 of Power System Relaying
Committee of IEEE Power Engineering Society, May 1995; Papers 96WM 016‐6
PWRD and 96WM 127‐1 PWRD, 1996 IEEE Power Engineering Society Winter
Meeting.
8. “Analysis And Guidelines For Testing Numerical Protection Schemes,” Final Report of
CIGRE WG 34.10, August 2000.
9. “Use of Preventative Maintenance and System Performance Data to Optimize
Scheduled Maintenance Intervals,” H. Anderson, R. Loughlin, and J. Zipp, Georgia
Tech Protective Relay Conference, May 1996.
10. “Battery Performance Monitoring by Internal Ohmic Measurements” EPRI
Application Guidelines for Stationary Batteries TR‐ 108826 Final Report, December
1997.
11. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve‐
Regulated Lead‐Acid (VRLA) Batteries for Stationary Applications,” IEEE Power
Engineering Society Std 1188 – 2005.
12. “IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead‐Acid Batteries for Stationary Applications,” IEEE Power & Engineering Society
Std 45‐2010.
13. “IEEE Recommended Practice for Installation design and Installation of Vented Lead‐
Acid Batteries for Stationary Applications,” IEEE Std 484 – 2002.
14. “Stationary Battery Monitoring by Internal Ohmic Measurements,” EPRI Technical
Report, 1002925 Final Report, December 2002.
15. “Stationary Battery Guide: Design Application, and Maintenance” EPRI Revision 2 of
TR‐100248, 1006757, August 2002.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
101
PSMT SDT References
16. “Essentials of Statistics for Business and Economics” Anderson, Sweeney, Williams,
2003
17. “Introduction to Statistics and Data Analysis” ‐ Second Edition, Peck, Olson, Devore,
2005
18. “Statistical Analysis for Business Decisions” Peters, Summers, 1968
19. “Considerations for Maintenance and Testing of Autoreclosing Schemes,” NERC
System Analysis and Modeling Subcommittee and NERC System Protection and
Control Subcommittee, November 2012
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
102
Figures
Figure 1: Typical Transmission System
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
103
Figure 2: Typical Generation System
Note: Figure 2 may show elements that are not included within PRC‐005‐2, and also
may not be all‐inclusive; see the Applicability section of the standard for specifics.
For information on components, see Figure 1 & 2 Legend – components of Protection
Systems
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
104
Figure 1 & 2 Legend – Components of Protection Systems
Number in
Figure
Includes
Excludes
1
Protective relays
which respond to
electrical quantities
All protective relays that use
current and/or voltage inputs
from current & voltage sensors
and that trip the 86, 94 or trip
coil.
Devices that use non‐electrical
methods of operation including
thermal, pressure, gas accumulation,
and vibration. Any ancillary
equipment not specified in the
definition of Protection Systems.
Control and/or monitoring equipment
that is not a part of the automatic
tripping action of the Protection
System
2
Voltage and current
sensing devices
providing inputs to
protective relays
The signals from the voltage &
current sensing devices to the
protective relay input.
Voltage & current sensing devices that
are not a part of the Protection
System, including sync‐check systems,
metering systems and data acquisition
systems.
Control circuitry
associated with
protective functions
All control wiring (or other
medium for conveying trip
signals) associated with the
tripping action of 86 devices, 94
devices or trip coils (from all
parallel trip paths). This would
include fiber‐optic systems that
carry a trip signal as well as hard‐
wired systems that carry trip
current.
Closing circuits, SCADA circuits, other
devices in control scheme not passing
trip current
Station dc supply
Batteries and battery chargers
and any control power system
which has the function of
supplying power to the
protective relays, associated trip
circuits and trip coils.
Any power supplies that are not used
to power protective relays or their
associated trip circuits and trip coils.
Communications
Tele‐protection equipment used
systems necessary
to convey specific information, in
for correct operation
the form of analog or digital
of protective
signals, necessary for the correct
functions
operation of protective functions.
Any communications equipment that
is not used to convey information
necessary for the correct operation of
protective functions.
3
4
5
Component of
Protection System
Additional information can be found in References
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
105
Appendix A
The following illustrates the concept of overlapping verifications and tests as summarized in
Section 10 of the paper. As an example, Figure A‐1 shows protection for a critical transmission
line by carrier blocking directional comparison pilot relaying. The goal is to verify the ability of
the entire two‐terminal pilot protection scheme to protect for line Faults, and to avoid over‐
tripping for Faults external to the transmission line zone of protection bounded by the current
transformer locations.
Figure A-1
In this example (Figure A1), verification takes advantage of the self‐monitoring features of
microprocessor multifunction line relays at each end of the line. For each of the line relays
themselves, the example assumes that the user has the following arrangements in place:
1. The relay has a data communications port that can be accessed from remote locations.
2. The relay has internal self‐monitoring programs and functions that report failures of
internal electronics, via communications messages or alarm contacts to SCADA.
3. The relays report loss of dc power, and the relays themselves or external monitors report
the state of the dc battery supply.
4. The CT and PT inputs to the relays are used for continuous calculation of metered values of
volts, amperes, plus Watts and VARs on the line. These metered values are reported by data
communications. For maintenance, the user elects to compare these readings to those of
other relays, meters, or DFRs. The other readings may be from redundant relaying or
measurement systems or they may be derived from values in other protection zones.
Comparison with other such readings to within required relaying accuracy verifies voltage &
current sensing devices, wiring, and analog signal input processing of the relays. One
effective way to do this is to utilize the relay metered values directly in SCADA, where they
can be compared with other references or state estimator values.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
106
5. Breaker status indication from auxiliary contacts is verified in the same way as in (2). Status
indications must be consistent with the flow or absence of current.
6. Continuity of the breaker trip circuit from dc bus through the trip coil is monitored by the
relay and reported via communications.
7. Correct operation of the on‐off carrier channel is also critical to security of the Protection
System, so each carrier set has a connected or integrated automatic checkback test unit.
The automatic checkback test runs several times a day. Newer carrier sets with integrated
checkback testing check for received signal level and report abnormal channel attenuation
or noise, even if the problem is not severe enough to completely disable the channel.
These monitoring activities plus the check‐back test comprise automatic verification of all the
Protection System elements that experience tells us are the most prone to fail. But, does this
comprise a complete verification?
Figure A-2
The dotted boxes of Figure A‐2 show the sections of verification defined by the monitoring and
verification practices just listed. These sections are not completely overlapping, and the shaded
regions show elements that are not verified:
1. The continuity of trip coils is verified, but no means is provided for validating the ability of
the circuit breaker to trip if the trip coil should be energized.
2. Within each line relay, all the microprocessors that participate in the trip decision have
been verified by internal monitoring. However, the trip circuit is actually energized by the
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
107
contacts of a small telephone‐type "ice cube" relay within the line protective relay. The
microprocessor energizes the coil of this ice cube relay through its output data port and a
transistor driver circuit. There is no monitoring of the output port, driver circuit, ice cube
relay, or contacts of that relay. These components are critical for tripping the circuit breaker
for a Fault.
3. The check‐back test of the carrier channel does not verify the connections between the
relaying microprocessor internal decision programs and the carrier transmitter keying
circuit or the carrier receiver output state. These connections include microprocessor I/O
ports, electronic driver circuits, wiring, and sometimes telephone‐type auxiliary relays.
4. The correct states of breaker and disconnect switch auxiliary contacts are monitored, but
this does not confirm that the state change indication is correct when the breaker or switch
opens.
A practical solution for (1) and (2) is to observe actual breaker tripping, with a specified
maximum time interval between trip tests. Clearing of naturally‐occurring Faults are
demonstrations of operation that reset the time interval clock for testing of each breaker
tripped in this way. If Faults do not occur, manual tripping of the breaker through the relay trip
output via data communications to the relay microprocessor meets the requirement for
periodic testing.
PRC‐005‐3 does not address breaker maintenance, and its Protection System test requirements
can be met by energizing the trip circuit in a test mode (breaker disconnected) through the
relay microprocessor. This can be done via a front‐panel button command to the relay logic, or
application of a simulated Fault with a relay test set. However, utilities have found that
breakers often show problems during Protection System tests. It is recommended that
Protection System verification include periodic testing of the actual tripping of connected
circuit breakers.
Testing of the relay‐carrier set interface in (3) requires that each relay key its transmitter, and
that the other relay demonstrate reception of that blocking carrier. This can be observed from
relay or DFR records during naturally occurring Faults, or by a manual test. If the checkback test
sequence were incorporated in the relay logic, the carrier sets and carrier channel are then
included in the overlapping segments monitored by the two relays, and the monitoring gap is
completely eliminated.
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
108
Appendix B
Protection System Maintenance Standard Drafting Team
Charles W. Rogers
Chairman
Consumers Energy Co.
John B. Anderson
Xcel Energy
Merle Ashton
Tri‐State G&T
Bob Bentert
Florida Power & Light Company
Forrest Brock
Western Farmers Electric Cooperative
Aaron Feathers
Pacific Gas and Electric Company
Sam Francis
Oncor Electric Delivery
David Harper
NRG Texas Maintenance Services
Carol Gerou
Midwest Reliability Organization
James M. Kinney
FirstEnergy Corporation
Russell C. Hardison
Tennessee Valley Authority
Mark Lucas
ComEd
David Harper
NRG Texas Maintenance Services
Kristina Marriott
ENOSERV James M. Kinney
FirstEnergy Corporation
Mark Lucas
ComEd
Kristina Marriott
ENOSERV
Al McMeekin
NERC
Michael Palusso
Southern California Edison
Mark Peterson
Great River Energy
John Schecter
American Electric Power
William D. Shultz
Southern Company Generation
Eric A. Udren
Quanta Technology
Scott Vaughan
City of Roseville Electric Department
Matthew Westrich
American Transmission Company
Philip B. Winston
Southern Company Transmission
John A. Zipp
ITC HoldingsDavid Youngblood
Luminant Power
John A. Zipp
ITC Holdings
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
109
PRC‐005‐3 Supplementary Reference and FAQ – April October 2013
110
Standards Announcement
Project 2007-17.2 Protection System Maintenance and Testing
Phase 2 (Reclosing Relays) PRC-005-3
A Final Ballot is now open through October 25, 2013
Now Available
A final ballot for PRC-005-3 – Protection System and Automatic Reclosing Maintenance is open
through 8 p.m. Eastern on Friday, October 25, 2013.
Background information for this project can be found on the project page.
Instructions
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their previously cast votes. A ballot pool member who failed to
cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a ballot
pool member does not participate in the final ballot, that member’s vote cast in the previous ballot
will be carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps
Voting results for the standard will be posted and announced after the ballot window closes. If
approved, the standard will be submitted to the Board of Trustees for adoption.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-17.2 PSMT Phase 2 (Reclosing Relays)
2
Standards Announcement
Project 2007-17.2 Protection System Maintenance and Testing
Phase 2 (Reclosing Relays)
PRC-005-3
Final Ballot Results
Now Available
A final ballot for PRC-005-3 – Protection System and Automatic Reclosing Maintenance concluded at 8
p.m. Eastern on Friday, October 25, 2013.
This standard achieved a quorum and sufficient affirmative votes for approval. Voting statistics are
listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Approval
Quorum: 85.71%
Approval: 85.38%
Background information for this project can be found on the project page.
Next Steps
The standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC Standards
Newsroom • Site Map • Contact NERC
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User Name
Ballot Results
Ballot Name: Project 2007-17.2 PRC-005-3 Final Ballot
Password
Ballot Period: 10/16/2013 - 10/25/2013
Ballot Type: Final Ballot
Log in
Total # Votes: 348
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 406
Quorum: 85.71 % The Quorum has been reached
Weighted Segment
85.38 %
Vote:
Ballot Results: A quorum was reached and there were sufficient affirmative votes for approval
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
107
1
63
0.788
17
0.213
0
9
17
9
0.5
4
0.4
1
0.1
0
3
1
95
1
60
0.857
10
0.143
0
12
13
33
1
20
0.909
2
0.091
0
5
6
92
1
55
0.764
17
0.236
0
8
12
53
1
34
0.773
10
0.227
0
3
6
0
0
0
0
0
0
0
0
0
6
0.3
3
0.3
0
0
0
0
3
2
0.2
2
0.2
0
0
0
0
0
9
0.9
9
0.9
0
0
0
0
0
406
6.9
250
5.891
57
1.01
0
40
58
Individual Ballot Pool Results
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
NERC Standards
Segment
Organization
Ballot
Member
1
Ameren Services
Eric Scott
1
American Electric Power
Paul B Johnson
Negative
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
David Rudolph
Patricia Robertson
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Kevin J Lyons
Joseph Turano Jr.
Negative
Abstain
Negative
1
1
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
Basin Electric Power Cooperative
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Iowa Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
1
Cleco Power LLC
Danny McDaniel
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
Affirmative
Affirmative
Michael Moltane
Affirmative
1
1
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
JEA
Jim D Cyrulewski
Ted Hobson
Affirmative
Affirmative
1
KAMO Electric Cooperative
Walter Kenyon
1
Kansas City Power & Light Co.
Jennifer Flandermeyer
1
1
1
1
1
1
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
1
Manitoba Hydro
Nazra S Gladu
1
1
1
1
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
1
1
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Chang G Choi
Affirmative
Daniel S Langston
Jack Stamper
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
NERC
Notes
Negative
COMMENT
RECEIVED
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
Affirmative THIRD PARTY
COMMENTS
COMMENT
Negative
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
1
1
1
Mark Ramsey
Michael Jones
Cole C Brodine
1
1
1
1
1
1
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
1
Oklahoma Gas and Electric Co.
Terri Pyle
1
1
1
1
1
1
1
1
1
1
1
1
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Affirmative
Affirmative
Affirmative
Abstain
Dale Dunckel
Affirmative
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority
Southern California Edison Company
Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams
Steven Mavis
Robert A. Schaffeld
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
Tracy Sliman
John Tolo
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Affirmative
Affirmative
Affirmative
Affirmative
1
Western Area Power Administration
Lloyd A Linke
Negative
1
Xcel Energy, Inc.
Gregory L Pieper
Negative
2
BC Hydro
2
Electric Reliability Council of Texas, Inc.
Venkataramakrishnan
Vinnakota
Cheryl Moseley
2
Independent Electricity System Operator
Barbara Constantinescu
2
2
2
2
2
2
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
1
1
Affirmative
Negative
Abstain
Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan
Robert Mattey
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Affirmative
Abstain
Affirmative
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
NERC Standards
3
AEP
Michael E Deloach
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Alabama Power Company
Ameren Services
American Public Power Association
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blue Ridge Electric
Bonneville Power Administration
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
City of Anaheim Public Utilities Department
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Redding
City of Tallahassee
City of Vineland
Robert S Moore
Mark Peters
Nathan Mitchell
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
James L Layton
Rebecca Berdahl
Adam M Weber
Thomas C Duffy
Dennis M Schmidt
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Bill Hughes
Bill R Fowler
Kathy Caignon
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
3
Cleco Corporation
Michelle A Corley
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power & Light Co.
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Charles Morgan
John Bee
Peter T Yost
Gerald G Farringer
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Summer C Esquerre
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
3
Kansas City Power & Light Co.
Charles Locke
3
3
3
3
3
3
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Gregory D Woessner
Mace D Hunter
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
3
Manitoba Hydro
Greg C. Parent
3
3
3
3
3
3
3
3
3
3
3
3
3
Manitowoc Public Utilities
MEAG Power
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Ocala Electric Utility
Thomas E Reed
Roger Brand
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
David Anderson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
3
Oklahoma Gas and Electric Co.
Donald Hargrove
3
3
3
3
3
3
3
3
3
3
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
3
Public Service Electric and Gas Co.
Jeffrey Mueller
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Blue Ridge Power Agency
Buckeye Power, Inc.
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Duane S Dahlquist
Manmohan K Sachdeva
Reza Ebrahimian
Kevin McCarthy
4
Consumers Energy Company
Tracy Goble
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Illinois Municipal Electric Agency
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Bob C. Thomas
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Henry E. LuBean
Abstain
Abstain
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Affirmative
Affirmative
Affirmative
4
4
4
4
4
4
4
4
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
Affirmative
Affirmative
Margaret Powell
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED
NERC Standards
4
South Mississippi Electric Power Association
Steven McElhaney
4
4
4
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
5
AEP Service Corp.
Brock Ondayko
5
5
5
5
5
5
5
Sam Dwyer
Scott Takinen
Brent R Carr
Matthew Pacobit
Steve Wenke
Clement Ma
George Tatar
5
Amerenue
Arizona Public Service Co.
Arkansas Electric Cooperative Corporation
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
5
Buckeye Power, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Paul M Jackson
Hamid Zakery
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
5
Cleco Power
Stephanie Huffman
Negative
5
5
5
5
5
5
5
5
5
5
5
5
5
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Gustavo Estrada
John R Cashin
Tracey Stubbs
5
Essential Power, LLC
Patrick Brown
5
5
5
5
5
5
5
5
5
5
Exelon Nuclear
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
Lincoln Electric System
Dennis Florom
Negative
5
5
5
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Kenneth Silver
Karin Schweitzer
Rick Terrill
5
Manitoba Hydro
S N Fernando
Negative
David Gordon
Affirmative
Steven Grego
Neil D Hammer
Affirmative
Affirmative
5
5
5
5
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Mike D Kukla
Francis J. Halpin
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
5
Muscatine Power & Water
Mike Avesing
Negative
5
Nebraska Public Power District
Don Schmit
Negative
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
Affirmative
Abstain
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
5
Occidental Chemical
Oglethorpe Power Corporation
Michelle R DAntuono
Bernard Johnson
5
Oklahoma Gas and Electric Co.
Leo Staples
5
5
5
5
5
5
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
Mahmood Z. Safi
David Ramkalawan
Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
5
PSEG Fossil LLC
Tim Kucey
Negative
5
Public Utility District No. 1 of Lewis County
Steven Grega
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
5
5
5
5
5
5
5
5
5
5
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Feather Power Project
Southern California Edison Company
5
Southern Company Generation
William D Shultz
Negative
5
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Abstain
Affirmative
5
Tri-State G & T Association, Inc.
Mark Stein
5
5
5
5
5
5
5
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Utility System Effeciencies, Inc. (USE)
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Melissa Kurtz
Erika Doot
Robert L Dintelman
Bryan Taggart
Linda Horn
Scott E Johnson
Liam Noailles
6
AEP Marketing
Edward P. Cox
6
6
6
6
6
6
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
6
Cleco Power LLC
Robert Hirchak
Negative
6
6
6
6
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Affirmative
Affirmative
Affirmative
Negative
5
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC Standards
6
6
6
6
6
6
6
6
Duke Energy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Greg Cecil
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
6
Lincoln Electric System
Eric Ruskamp
6
6
Los Angeles Department of Water & Power
Luminant Energy
Brad Packer
Brenda Hampton
6
Manitoba Hydro
Blair Mukanik
Negative
6
6
MidAmerican Energy Co.
Modesto Irrigation District
Dennis Kimm
James McFall
Affirmative
6
Muscatine Power & Water
John Stolley
Negative
6
6
6
6
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
NRG Energy, Inc.
Saul Rojas
Steve C Hill
Joseph O'Brien
Alan Johnson
Affirmative
Affirmative
Affirmative
6
Oklahoma Gas & Electric Services
Jerry Nottnagel
Negative
6
6
6
6
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
6
PSEG Energy Resources & Trade LLC
Peter Dolan
6
6
6
6
6
6
6
6
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
6
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
6
Xcel Energy, Inc.
David F Lemmons
8
8
8
8
8
8
Foundation for Resilient Societies
Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Edward C Stein
Merle Ashton
Roger C Zaklukiewicz
William R Harris
Frederick R Plett
Terry Volkmann
Affirmative
Donald Nelson
Affirmative
Diane J. Barney
Affirmative
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Emily Pennel
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
6
6
6
6
6
6
9
9
10
10
10
10
10
10
10
Peter H Kinney
David Hathaway
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS
NERC Standards
10
10
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Donald G Jones
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=54918964-c880-4799-a06e-e7ee476bba55[10/28/2013 11:44:56 AM]
Affirmative
Affirmative
Exhibit I
Standard Drafting Team Roster
Standard Drafting Team Roster
Project 2007-17.2 Protection System Maintenance and
Testing Phase 2 (Reclosing Relays)
Member
Bio
John Anderson
Principal Engineer
John Anderson is presently a Principal Engineer with Xcel Energy
and is responsible for the development and implementation of the
company’s power plant electrical distribution system equipment
Xcel Energy, Inc.
maintenance programs including those for plant protective relay
1518 Chestnut Avenue N. 2nd
systems, power transformers, circuit breakers and battery systems.
Floor
He has served in this capacity since 1998. Prior to taking on this
Minneapolis MN 55403
fleet wide coordination role, he served for 8 years as an Electrical
System Engineer at Xcel Energy’s Monticello Nuclear Generating
Business: (612) 630-4630
Station with responsibilities including coordination of the plant’s
protection system testing program. During this time, Mr. Anderson
[email protected] earned a Senior Reactor Operator Certification for the plant. Prior
to joining Northern State Power Company in 1990, Mr. Anderson
completed the Navy Nuclear Propulsion Officer training program
and served as a Nuclear Propulsion Plant Watch Officer and
Electrical Distribution Officer aboard the USS ENTERPRISE (CVN65). He holds a BSEE from the University of Minnesota.
Merle Ashton
Substation Maintenance
Supervisor
Tri-State G & T Association, Inc.
12496 Rd 23
Cortez CO 81321
Business: (970) 759-6139
[email protected]
Rick Ashton is presently a Substation Maintenance Supervisor for
Tri-State Generation and Transmission Assn., Inc. Rick has held this
position since 2006; prior to 2006 Rick was a Substation Technician
for this same company since 1981. As a Substation Technician,
Rick’s primary responsibility was the maintenance of Protection
System components and other equipment within the substation
yard and control house. Relays (protective and otherwise),
batteries, transformers, circuit breakers, regulators, switches were
all within his area of influence. These years of hands-on experience
provided Rick opportunities to observe and investigate many
different equipment failures; to use a variety of test equipment,
and employ many test methods. As owner/operator of
relaytech.com, Rick has authored many titles of “how-to” books
that assist in the training of relay technicians. Rick travels to
utilities, testing companies, and consulting firms upon request for
training relay technicians, and other personnel. Rick imparts his
overall knowledge of Protection Systems, their characteristics and
interactions, as well as the math and theory behind it all, providing
technical personnel with a better working understanding of the
entire substation.
Forrest D. Brock
Superintendent of Station
Services
Western Farmers Electric
Cooperative
701 NE 7th Street
PO Box 429
Anadarko, Oklahoma, 73005-0429
Business: (405) 247-4360
[email protected]
Aaron Feathers
Principal Engineer
Pacific Gas and Electric Company
487 W. Shaw Avenue, Building A
Fresno, CA 93704
Business: (559)263-5011
[email protected]
Samuel Francis
System Protection Specialist
Oncor Electric Delivery
115 W. 7th Street
Suite 3114
P. O. Box 970
Fort Worth TX 76101
Standard Drafting Team Roster
Project 2007-17.2 PSMT
Forrest Brock is the Superintendent of Station Services at Western
Farmers Electric Cooperative – a generation and transmission
cooperative serving 22 distribution cooperative members in
Oklahoma and New Mexico. Forrest has 23 years of protection and
control experience earned through his service as a relay technician
and supervisor, along with two years serving as Transmission
Compliance Specialist prior to his promotion to department
superintendent in 2012. In 2009, Forrest began serving as a
participating and contributing observer on the Standard Drafting
Team for Project 2007-17 and became an official SDT member in
2011. Forrest is also a member of the Standard Drafting Team for
Project 2007-06 System Protection Coordination developing NERC
Reliability Standard PRC-027-1, and represents Cooperatives as a
member of the NERC System Protection and Control
Subcommittee (SPCS).
Aaron Feathers is presently a Principal Engineer in System
Protection at Pacific Gas and Electric Company, where he has been
employed since 1992. He has 20 years of experience in the
application of protective relaying and control systems on
transmission systems. Aaron's current job responsibilities include
design standards, wide area RAS support, NERC PRC compliance,
and relay asset management support. He has a BSEE degree from
California State Polytechnic University, San Luis Obispo and is a
registered Professional Engineer in the State of California. He is
also a member of IEEE and is on the Western Protective Relay
Conference planning committee.
Samuel B. Francis is presently a System Protection Specialist for
Oncor Electric Delivery. Sam has over 35 years experience working
for Oncor Electric Delivery with 30 years of that time having been
spent in the area of System Protection in which he has served on
several taskforces and committees that have been responsible for
determining maintenance and testing procedures for the Oncor
Protection Systems. For the past 7 years, Mr. Francis has been a
member of the NERC System Protection and Control
Subcommittee (SPCS) formally the System Protection and Control
2
Business: (817) 215-6920
[email protected]
Ervin David Harper
I & E Specialist
NRG Texas Maintenance Services
12307 Kurland
Houston TX 77034
Task Force (SPCTF). Mr. Francis is also a member of the NERC
Protection System Maintenance and Testing Standard Drafting
Team (PSMTSDT) developing the NERC Reliability Standard PRC005-2. Sam has also been a member of the NERC System
Protection Coordination Standard Drafting Team (SPCSDT) since its
formation in 2008 developing NERC Reliability Standard PRC-027-1.
Mr. Francis holds a BSEE from Brigham Young University and is a
registered Professional Engineer in the State of Texas.
Ervin David Harper is presently I&E specialist for NRG Maintenance
Services responsible for protective system maintenance and
testing and system and equipment fault analysis. He has over 30
years experience in the maintenance and testing of generation
station equipment including generators, transformers, switchgear,
motors and protection and control systems.
Business: (713) 545-6019
[email protected]
James M. Kinney
Senior Engineer
FirstEnergy Corporation
76 South Main Street
Akron, OH 44308
Business: (419) 521-6252
[email protected]
Mark Lukas
T&S Engineering, Real Time
Analysis Manager
Commonwealth Edison Co.
Two Lincoln Centre 9th Floor
Oakbrook Terrace IL 60181-4260
Business: (630) 576-6891
Standard Drafting Team Roster
Project 2007-17.2 PSMT
James M. Kinney is presently a Senior Engineer, Transmission and
Substation Services at FirstEnergy Corporation. He has over 20
years of experience in the power industry including engineering,
operations and maintenance. Since 2000, he has been responsible
for substation commissioning as well as substation maintenance
and testing programs at FirstEnergy Corporation. He is a senior
member IEEE, a member of the IEEE Power and Energy Society, an
individual member of the IEEE Standards Association, and also an
individual member of Cigre’. He holds a BSEE from The Ohio State
University and is a registered Professional Engineer in the State of
Ohio.
Mark Lukas has worked for ComEd in various Protection and
Control roles for most of his 36 years. Upon graduating from
Purdue University-Calumet in 1979, early responsibilities were in
the Operational Analysis (Field Testing) Department performing
Substation Relay and Equipment installations, maintenance, and
troubleshooting. Subsequent moves were into manager roles in
various Operational Analysis sections and then managing the Relay
and Protection Engineering - SCADA Standards group. Mark has
currently been managing the Relay and Protection Engineering Real Time Analysis group for 12 years. Mark’s current
3
[email protected]
duties/responsibilities include 7x24 operational analysis support
for Transmission & Substation automatic operations, abnormal
system configuration evaluations, as well as abnormal protection
system conditions evaluations.
Kristina Marriott
Senior Project Manager &
Application Consultant
Kristina Marriott has been the Senior Project Manager at ENOSERV
for over 3 years and has worked for ENOSERV over 5. Her primary
job consists of consulting & data application projects. Many of her
projects have been geared to Transmission and Distribution, where
she works with Engineering and Technical groups to develop,
implement, and support maintenance Programs for Protection
System components and other equipment utilizing multiple
systems & applications. Prior to her Project Manager position, she
supported multiple utilities in troubleshooting and maintaining
Protective Relays. She has extensive knowledge and experience
with asset management, business plans, policies, regulatory
compliance, and continues to take an extreme interest in
Protection and Control.
ENOSERV
7708 East 106th Street
Tulsa, Ok 74133
Business: (918) 622-4530 x 110
[email protected]
Al McMeekin
Standards Development Advisor
NERC
3353 Peachtree Rd. NE
Suite 600, North Tower
Atlanta, GA 30326
Business (803) 530-1963
[email protected]
Michael Palusso
Manager Transmission/Substation
FERC/NERC/CAISO/CPUC
Compliance
Standard Drafting Team Roster
Project 2007-17.2 PSMT
Al McMeekin is the NERC Staff Advisor for Project 2007-17
(Protection System Maintenance and Testing – PRC-005). Prior to
joining NERC in 2009, Mr. McMeekin worked at South Carolina
Electric & Gas Company for 29 years as an engineer in distribution
operations and engineering, and in Transmission Operations
Planning. Al participated in SCE&G’s ERO Working Group to ensure
compliance with NERC standards; and represented SCE&G on
various national, regional, and subregional groups. Mr. McMeekin
was a member of the SERC Operating Committee and served as
Chair of the SERC Operations Planning Subcommittee. Al was a
member of the SERC Standards Committee and the SERC Available
Transfer Capability Working Group. He also served as Chair of the
VACAR South Reliability Coordinator Procedures Working Group,
and was a member of Project 2006-03 (System Restoration and
Blackstart – EOP-005 & EOP-006) Standards Drafting Team. Al
holds a BSAgE degree from Clemson University and is a registered
Professional Engineer in South Carolina.
Mike Palusso has been part of the Southern California Edison
company for 30 years. Throughout his career Mike held numerous
positions in the substation area culminating as the Manager for
Power Utility Substation Equipment and Relay. Mike is currently
the Manager for Transmission/Substation Maintenance &
4
Southern California Edison (SCE)
3 Innovation Way
Pomona, CA, 91768
Business: (909) 274-3460
[email protected]
Charles W. Rogers
Principal Engineer
Consumers Energy
1945 W. Parnall Road
Jackson, Michigan 49201
Business: (517) 788-0027
[email protected]
John E. Schechter
Manager, Protection & Control
Engineering Office
American Electric Power
700 Morrison Road
Gahanna OH 43230
(614) 552-1908
Standard Drafting Team Roster
Project 2007-17.2 PSMT
Inspection Compliance. His responsibilities encompass compliance
for NERC/WECC/CAISO, as well as CPUC compliance reporting for
protection and control systems, substation equipment, vegetation
management, and transmission line equipment. Mike also
represents SCE’s interests on the CAISO Transmission Maintenance
Coordination Committee.
Charles Rogers is a Principal Engineer at Consumers Energy, where
he has been employed since 1978. For the bulk of his career, has
been responsible for application of protective relaying to the
transmission and distribution systems, and is currently responsible
for managing compliance to NERC Standards for the "wires"
portion of Consumers Energy. He chaired the NERC System
Protection and Control Task Force from its inception in 2004
through May 2008, and continues to be a member of its successor
group, the NERC System Protection and Control Task Force, and
was a member of the NERC Planning Committee in 2009. He
chaired the ECAR investigation into the August 2003 blackout,
chaired the ECAR Protection Panel for several years, and chaired
the RFC Protection Subcommittee from its inception in 2006
through 2012. At NERC, he was a member of the "Phase II
Standard Drafting Team" in 2005-2006, chaired the standard
drafting team that developed PRC-023-1, and currently chairs the
standard drafting teams assigned to Projects 2007-17 (Protection
System Maintenance) and 2010-13 (addressing FERC Order 733).
At RFC, he also chaired the standard drafting team that developed
PRC-002-RFC. Charles is also a member of IEEE Standards
Coordinating Committee 21, and was a key member of the working
groups that developed IEEE 1547, IEEE 1547.2, and IEEE 1547.4.
He received his BSEE degree from Michigan Technological
University in 1978. He is a registered professional engineer in the
State of Michigan, and is a Senior Member of IEEE.
John Schechter is Manager of American Electric Power’s Protection
& Control Engineering office in Columbus, Ohio. John has been
with American Electric Power (AEP) or its operating companies
since 1980. He has held many positions with increasing
responsibility in substation operation, construction, maintenance
or engineering spanning 32 years and has also held supervisory or
managerial positions in distribution line design, distribution service
dispatching, overhead and underground distribution maintenance
and construction, and transmission line asset management.
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[email protected]
William D. Shultz
Engineering Manager
Southern Company Generation
42 Inverness Center Parkway
Mail Bin B425
Birmingham AL 35242
Business: (205) 992-5526
[email protected]
Eric Udren
Executive Advisor
Quanta Technology, LLC
1395 Terrace Drive
Pittsburgh, PA 15228
Business: (412)-596-6959
[email protected]
Standard Drafting Team Roster
Project 2007-17.2 PSMT
Following the 2003 blackout, John was named to the NERC
Transmission Vegetation Management (VM) task force to draft the
new vegetation management standard. He was named to the NERC
PRC-005-2 revision drafting team in 2011. John received the
B.S.E.E. degree in electrical engineering from the University of
Cincinnati, the M.S.E.E. degree in electric power systems
engineering from The Ohio State University, and the M.B.A. degree
from the University of Notre Dame. He is a registered professional
engineer in the states of Indiana and Ohio.
Bill Shultz is presently Engineering Manager, Electrical Services and
Field Support, Technical Services of Southern Company
Generation. He has 29 years of experience in Generating Plant
Technical Services, including protective equipment application,
start-up commissioning, and maintenance of protective relaying
and control systems for electric power generating plants. His work
experience includes the commissioning and maintenance of the
control and protection of static excitation systems, variable speed
drives, and emergency generation. He is active in Southern
Company reliability standards compliance efforts as well as being
involved in regional and national organizations responsible for
utility reliability standards. He holds a BSEE from the University of
Tennessee, a MSEE from Auburn University, and is a registered
Professional Engineer in the State of Alabama.
Eric A. Udren has a 43 year distinguished career in design and
application of protective relaying, utility substation control, and
communications systems. He developed protection software for
the world’s first computer based transmission line relaying system,
as well as for the world’s first substation P&C system based on
local area network communications. He has worked with major
utilities to develop new substation protection, control, data
communications, SPS, and wide area monitoring and protection
system designs, including major projects for substation integration
based on IEC 61850. He currently serves as Executive Advisor with
Quanta Technology, LLC of Raleigh, NC with his office in Pittsburgh,
PA. Eric is IEEE Fellow, Chair of the Relaying Communications
Subcommittee of the IEEE Power System Relaying Committee
(PSRC) and chairs two standards working groups of PSRC. He is
Technical Advisor to the US National Committee of IEC for
protective relay standards from TC 95; and is member of the IEC TC
57 WG 10 that develops IEC 61850 power systems communications
6
and integration protocol. Eric serves on the NERC System
Protection and Control Subcommittee (SPCS), as well as the subject
PRC-005-2 Drafting Team. He has written and presented over 90
technical papers and book chapters.
Scott Vaughan, P.E.
Electrical Engineering Manager
Roseville Electric
2090 Hilltop Circle
Roseville, CA 95747
Business: (916) 774-5604
[email protected]
Mathew J. Westrich, P.E.
Assistant Manager Asset
Maintenance
American Transmission Co. (ATC)
Business: 906-779-7901
Scott Vaughan is currently the Electrical Engineering Manager of
Roseville Electric. He has over 18 years of industry experience. In
his current position, Mr. Vaughan is responsible for the operation,
design and construction of electrical facilities within the City of
Roseville. Throughout his career, he has held positions as a
protection, generation facility design, and substation design
engineer. He has worked as the Subject Matter Expert (SME) for
Roseville Electric since 2007 and is currently the responsible
engineer for compliance with the NERC mandatory reliability
standards relating to the city’s registration as a Distribution
Provider, Generator Operator and Generator Owner. Mr. Vaughan
holds a BSEE from the California Polytechnical State University at
San Luis Obispo, a MBA from Golden Gate University and is a
registered engineer in the State of California.
Mathew Westrich is presently the Assistant Manager Asset
Maintenance for American Transmission Company. Previously
Matt held positions as Substation Maintenance Engineer and Asset
Manager with ATC. He also worked for Wisconsin Energies as a
relay testing technician since 1982. He has over 30 years’
experience in Protection, Commissioning and Maintenance. He is a
licensed P.E. with the State of Wisconsin.
[email protected]
Philip B. Winston
Chief Engineer, Protection and
Control Applications
Southern Company
62 Like Mirror Road
Bin # 50061
Forest Park, Georgia 30297
Business: (404) 608-5989
[email protected]
Standard Drafting Team Roster
Project 2007-17.2 PSMT
Philip B. Winston is presently the Chief Engineer, Protection and
Control Applications for Southern Company Transmission.
Previously he was the Manager, Protection and Control
Applications with Georgia Power Company since 1991. With over
40 years experience in Protection, Operations, Engineering, and
Maintenance, he has been active in Southern Company
standardization efforts as well as being involved in regional and
national organizations responsible for utility standards and
disturbance analysis. He is a past Chairman of the IEEE/ Power
System Relaying Committee, a past Chair of the PSRC Systems
Protection and the Line Protection Subcommittees, presently the
Standards Coordinator for IEEE PSRC and serves on the IEEE
7
Standards Association Standards Board, NesCom, ProCom, and
Awards Committee. He is the Vice Chair of the NERC SPCS, and
serves on several NERC Standard Drafting Teams including the
Chair of Project 2007-06 System Protection Coordination SDT. He
holds a BSEE from Clemson University, a MSEE from Georgia Tech,
and is a registered Professional Engineer in the State of Georgia.
John Zipp
Senior Staff Engineer
ITC Holdings
27175 Energy Way
Novi MI 48377
Business: (248) 946-3289
[email protected]
Standard Drafting Team Roster
Project 2007-17.2 PSMT
John Zipp has over 30 years of transmission system protection
experience. He has 27 years of experience at Consumers Energy in
the System Protection area. He spent 20 years as the supervisor
of the Transmission System protection group directing protection
system design, setting, and managing the protective system
maintenance program at Consumers Energy. He was System
Control Supervisor for 4 years directing the south control room in
Jackson Michigan. He is presently a Senior Staff engineer at ITC
Holdings directing the Relay Engineering department since 2007.
He is an IEEE Senior member and was a member of the Power
System Relaying Technical Committee in the IEEE for 17 years
serving many working groups and as the Chair of the Line
Protection committee. He has a BSEE degree from Michigan Tech
and is a Registered professional Engineer in the State of Michigan.
8
| File Type | application/octet-stream |
| File Title | NERC |
| File Modified | 0000-00-00 |
| File Created | 0000-00-00 |