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pdfStandard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
A. Introduction
1.
Title: Protection System Misoperation Identification and Correction
2.
Number:
3.
Purpose:
Identify and correct the causes of Misoperations of Protection Systems
for Bulk Electric System (BES) Elements.
4.
Applicability:
PRC‐004‐5(i)
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 for BES Elements, with the following exclusions:
4.2.1.1 Non‐protective functions that are embedded within a Protection
System.
4.2.1.2 Protective functions intended to operate as a control function
during switching.1
4.2.1.3 Special Protection Systems (SPS).
4.2.1.4 Remedial Action Schemes (RAS).
4.2.1.5 Protection Systems of individual dispersed power producing
resources identified under Inclusion I4 of the BES definition where
the Misoperations affected an aggregate nameplate rating of less
than or equal to 75 MVA of BES Facilities.
4.2.2 Underfrequency load shedding (UFLS) that is intended to trip one or more
BES Elements.
4.2.3 Undervoltage load shedding (UVLS) that is intended to trip one or more
BES Elements.
5.
Effective Date: See Project 2008‐02.2 Implementation Plan.
1 For additional information and examples, see the “Non‐Protective Functions” and “Control Functions” sections in the
Application Guidelines.
Page 1 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
B. Requirements and Measures
R1. Each Transmission Owner, Generator Owner, and Distribution Provider that owns a
BES interrupting device that operated under the circumstances in Parts 1.1 through
1.3 shall, within 120 calendar days of the BES interrupting device operation, identify
whether its Protection System component(s) caused a Misoperation: [Violation Risk
Factor: High][Time Horizon: Operations Assessment, Operations Planning]
1.1 The BES interrupting device operation was caused by a Protection System or by
manual intervention in response to a Protection System failure to operate; and
1.2 The BES interrupting device owner owns all or part of the Composite Protection
System; and
1.3 The BES interrupting device owner identified that its Protection System
component(s) caused the BES interrupting device(s) operation or was caused by
manual intervention in response to its Protection System failure to operate.
M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it identified the Misoperation of its Protection
System component(s), if any, that meet the circumstances in Requirement R1, Parts
1.1, 1.2, and 1.3 within the allotted time period. Acceptable evidence for Requirement
R1, including Parts 1.1, 1.2, and 1.3 may include, but is not limited to the following
dated documentation (electronic or hardcopy format): reports, databases,
spreadsheets, emails, facsimiles, lists, logs, records, declarations, analyses of sequence
of events, relay targets, Disturbance Monitoring Equipment (DME) records, test
results, or transmittals.
Page 2 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R2. Each Transmission Owner, Generator Owner, and Distribution Provider that owns a
BES interrupting device that operated shall, within 120 calendar days of the BES
interrupting device operation, provide notification as described in Parts 2.1 and 2.2.
[Violation Risk Factor: High][Time Horizon: Operations Assessment, Operations
Planning]
2.1 For a BES interrupting device operation by a Composite Protection System or by
manual intervention in response to a Protection System failure to operate,
notification of the operation shall be provided to the other owner(s) that share
Misoperation identification responsibility for the Composite Protection System
under the following circumstances:
2.1.1 The BES interrupting device owner shares the Composite Protection
System ownership with any other owner; and
2.1.2 The BES interrupting device owner has determined that a Misoperation
occurred or cannot rule out a Misoperation; and
2.1.3 The BES interrupting device owner has determined that its Protection
System component(s) did not cause the BES interrupting device(s)
operation or cannot determine whether its Protection System
components caused the BES interrupting device(s) operation.
2.2 For a BES interrupting device operation by a Protection System component
intended to operate as backup protection for a condition on another entity’s BES
Element, notification of the operation shall be provided to the other Protection
System owner(s) for which that backup protection was provided.
M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates notification to the other owner(s), within the
allotted time period for either Requirement R2, Part 2.1, including subparts 2.1.1,
2.1.2, and 2.1.3 and Requirement R2, Part 2.2. Acceptable evidence for Requirement
R2, including Parts 2.1 and 2.2 may include, but is not limited to the following dated
documentation (electronic or hardcopy format): emails, facsimiles, or transmittals.
R3. Each Transmission Owner, Generator Owner, and Distribution Provider that receives
notification, pursuant to Requirement R2 shall, within the later of 60 calendar days of
notification or 120 calendar days of the BES interrupting device(s) operation, identify
whether its Protection System component(s) caused a Misoperation. [Violation Risk
Factor: High][Time Horizon: Operations Assessment, Operations Planning]
M3. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it identified whether its Protection System
component(s) caused a Misoperation within the allotted time period. Acceptable
evidence for Requirement R3 may include, but is not limited to the following dated
documentation (electronic or hardcopy format): reports, databases, spreadsheets,
emails, facsimiles, lists, logs, records, declarations, analyses of sequence of events,
relay targets, DME records, test results, or transmittals.
Page 3 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R4. Each Transmission Owner, Generator Owner, and Distribution Provider that has not
determined the cause(s) of a Misoperation, for a Misoperation identified in
accordance with Requirement R1 or R3, shall perform investigative action(s) to
determine the cause(s) of the Misoperation at least once every two full calendar
quarters after the Misoperation was first identified, until one of the following
completes the investigation: [Violation Risk Factor: High] [Time Horizon: Operations
Assessment, Operations Planning]
The identification of the cause(s) of the Misoperation; or
A declaration that no cause was identified.
M4. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it performed at least one investigative action
according to Requirement R4 every two full calendar quarters until a cause is
identified or a declaration is made. Acceptable evidence for Requirement R4 may
include, but is not limited to the following dated documentation (electronic or
hardcopy format): reports, databases, spreadsheets, emails, facsimiles, lists, logs,
records, declarations, analyses of sequence of events, relay targets, DME records, test
results, or transmittals.
R5. Each Transmission Owner, Generator Owner, and Distribution Provider that owns the
Protection System component(s) that caused the Misoperation shall, within 60
calendar days of first identifying a cause of the Misoperation: [Violation Risk Factor:
High] [Time Horizon: Operations Planning, Long‐Term Planning]
Develop a Corrective Action Plan (CAP) for the identified Protection System
component(s), and an evaluation of the CAP’s applicability to the entity’s other
Protection Systems including other locations; or
Explain in a declaration why corrective actions are beyond the entity’s control or
would not improve BES reliability, and that no further corrective actions will be
taken.
M5. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it developed a CAP and an evaluation of the CAP’s
applicability to other Protection Systems and locations, or a declaration in accordance
with Requirement R5. Acceptable evidence for Requirement R5 may include, but is not
limited to the following dated documentation (electronic or hardcopy format): CAP
and evaluation, or declaration.
R6. Each Transmission Owner, Generator Owner, and Distribution Provider shall
implement each CAP developed in Requirement R5, and update each CAP if actions or
timetables change, until completed. [Violation Risk Factor: High][Time Horizon:
Operations Planning, Long‐Term Planning]
Page 4 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
M6. Each Transmission Owner, Generator Owner, and Distribution Provider shall have
dated evidence that demonstrates it implemented each CAP, including updating
actions or timetables. Acceptable evidence for Requirement R6 may include, but is not
limited to the following dated documentation (electronic or hardcopy format): records
that document the implementation of each CAP and the completion of actions for
each CAP including revision history of each CAP. Evidence may also include work
management program records, work orders, and maintenance records.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
(CEA) means NERC or the Regional Entity in their respective roles of monitoring
and enforcing compliance with the NERC Reliability Standards.
1.2. 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 CEA 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 keep
data or evidence to show compliance as identified below unless directed by its CEA
to retain specific evidence for a longer period of time as part of an investigation.
The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirements R1, R2, R3, and R4, Measures M1, M2, M3,
and M4 for a minimum of 12 calendar months following the completion of
each Requirement.
The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirement R5, Measure M5, including any supporting
analysis per Requirements R1, R2, R3, and R4, for a minimum of 12 calendar
months following completion of each CAP, completion of each evaluation,
and completion of each declaration.
The Transmission Owner, Generator Owner, and Distribution Provider shall
retain evidence of Requirement R6, Measure M6 for a minimum of 12
calendar months following completion of each CAP.
If a Transmission Owner, Generator Owner, or Distribution Provider is found non‐
compliant, it shall keep information related to the non‐compliance until mitigation
is complete and approved, or for the time specified above, whichever is longer.
Page 5 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
The CEA shall keep the last audit records and all requested and submitted
subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
Compliance Audit
Self‐Certification
Spot Checking
Compliance Investigation
Self‐Reporting
Complaint
1.4. Additional Compliance Information
None.
Page 6 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
D. Table of Compliance Elements
R#
R1
Time
Horizon
VRF
Operations
Assessment,
Operations
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 120
calendar days and less
than or equal to 150
calendar days of the
BES interrupting
device operation.
The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 150
calendar days and less
than or equal to 165
calendar days of the
BES interrupting
device operation.
The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 165
calendar days and less
than or equal to 180
calendar days of the
BES interrupting
device operation.
The responsible entity
identified whether its
Protection System
component(s) caused
a Misoperation in
accordance with
Requirement R1, but
in more than 180
calendar days of the
BES interrupting
device operation.
OR
The responsible entity
failed to identify
whether its Protection
System component(s)
caused a Misoperation
in accordance with
Requirement R1.
Page 7 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R#
R2
Time
Horizon
VRF
Operations
Assessment,
Operations
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 120
calendar days and less
than or equal to 150
calendar days of the
BES interrupting
device operation.
The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 150
calendar days and less
than or equal to 165
calendar days of the
BES interrupting
device operation.
The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 165
calendar days and less
than or equal to 180
calendar days of the
BES interrupting
device operation.
The responsible entity
notified the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2, but
in more than 180
calendar days of the
BES interrupting
device operation.
OR
The responsible entity
failed to notify one or
more of the other
owner(s) of the
Protection System
component(s) in
accordance with
Requirement R2.
Page 8 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R#
R3
Time
Horizon
VRF
Operations
Assessment,
Operations
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
identified whether or
not its Protection
System component(s)
caused a Misoperation
in accordance with
Requirement R3, but
was less than or equal
to 30 calendar days
late.
The responsible entity
identified whether or
not its Protection
System component(s)
caused a Misoperation
in accordance with
Requirement R3, but
was greater than 30
calendar days and less
than or equal to 45
calendar days late.
The responsible entity
identified whether or
not its Protection
System component(s)
caused a Misoperation
in accordance with
Requirement R3, but
was greater than 45
calendar days and less
than or equal to 60
calendar days late.
The responsible entity
identified whether or
not its Protection
System component(s)
caused a Misoperation
in accordance with
Requirement R3, but
was greater than 60
calendar days late.
OR
The responsible entity
failed to identify
whether or not a
Misoperation of its
Protection System
component(s)
occurred in
accordance with
Requirement R3.
Page 9 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R#
R4
Time
Horizon
VRF
Operations
Assessment,
Operations
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
performed at least
one investigative
action in accordance
with Requirement R4,
but was less than or
equal to one calendar
quarter late.
The responsible entity
performed at least
one investigative
action in accordance
with Requirement R4,
but was greater than
one calendar quarter
and less than or equal
to two calendar
quarters late.
The responsible entity
performed at least
one investigative
action in accordance
with Requirement R4,
but was greater than
two calendar quarters
and less than or equal
to three calendar
quarters late.
The responsible entity
performed at least
one investigative
action in accordance
with Requirement R4,
but was more than
three calendar
quarters late.
OR
The responsible entity
failed to perform
investigative action(s)
in accordance with
Requirement R4.
Page 10 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R#
R5
Time
Horizon
VRF
Operations
Planning,
Long‐Term
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 60
calendar days and less
than or equal to 70
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 70
calendar days and less
than or equal to 80
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 80
calendar days and less
than or equal to 90
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed a CAP, or
explained in a
declaration in
accordance with
Requirement R5, but
in more than 90
calendar days of first
identifying a cause of
the Misoperation.
OR
OR
OR
(See next page)
(See next page)
(See next page)
OR
The responsible entity
failed to develop a
CAP or explain in a
declaration in
accordance with
Requirement R5.
OR
(See next page)
Page 11 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
R#
R5
R6
Time
Horizon
VRF
(Continued)
Operations
Planning,
Long‐Term
Planning
High
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 60
calendar days and less
than or equal to 70
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 70
calendar days and less
than or equal to 80
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 80
calendar days and less
than or equal to 90
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
developed an
evaluation in
accordance with
Requirement R5, but
in more than 90
calendar days of first
identifying a cause of
the Misoperation.
The responsible entity
implemented, but
failed to update a
CAP, when actions or
timetables changed, in
accordance with
Requirement R6.
N/A
N/A
OR
The responsible entity
failed to develop an
evaluation in
accordance with
Requirement R5.
The responsible entity
failed to implement a
CAP in accordance
with Requirement R6.
Page 12 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
E. Regional Variances
None.
F. Interpretations
None.
G. Associated Documents
NERC System Protection and Controls Subcommittee of the NERC Planning Committee,
Assessment of Standards: PRC‐003‐1 – Regional Procedure for Analysis of Misoperations of
Transmission and Generation Protection Systems, PRC‐004‐1 – Analysis and Mitigation of
Transmission and Generation Protection Misoperations, PRC‐016‐1 – Special Protection
System Misoperations, May 22, 2009.2
Version History
Version
0
Date
April 1, 2005
Action
Effective Date
Change Tracking
New
1. Changed incorrect use
of certain hyphens (‐) to
“en dash” (–) and “em
dash (—).”
1
December 1, 2005
2. Added “periods” to
items where appropriate.
01/20/06
3. Changed “Timeframe”
to “Time Frame” in item D,
1.2.
1a
1a
February 17, 2011
Project 2009‐17 interpretation
adding Appendix 1 ‐
Adopted by NERC Board of Interpretation regarding
Trustees
applicability of standard to
protection of radially
connected transformers
September 26, 2011
Appended FERC‐approved
interpretation of R1 and
R3 to version 1
FERC’s Order approving the
interpretation of R1 and R3 is
effective as of September 26,
2011
2 (http://www.nerc.com/comm/PC/System%20Protection%20and%20Control%20Subcommittee%20SPCS%20DL/PRC‐003‐004‐
016%20Report.pdf).
Page 13 of 37
Standard PRC‐004‐5(i) — Protection System Misoperation Identification and Correction
Version
Action
Change Tracking
August 5, 2010
Project 2010‐12 modifications
Adopted by NERC Board of to address Order No. 693
Trustees
Directives contained in
paragraph 1469
September 26, 2011
Appended FERC‐approved
interpretation of R1 and
R3 to version 2
2.1a
February 9, 2012
Errata change under Project
Adopted by NERC Board of 2010‐07 to add “…and
Trustees
generator interconnection
Facility…”
3
August 14, 2014
Adopted by NERC Board of Revision under Project 2010‐
Trustees
05.1
4
November 13, 2014
Applicability revision under
Project 2014‐01 to clarify
Adopted by NERC Board of
application of Requirements to
Trustees
BES dispersed power
producing resources
5
May 7, 2015
Adopted by NERC Board of Revision under Project 2008‐
Trustees
02.2
June 22, 2015
Revision to VRF designations
from “Medium” to “High” for
Requirements R1 through R6,
Adopted by NERC Board of in compliance with the Federal
Trustees
Energy Regulatory
Commission’s directive in N.
Am. Elec. Reliability Corp., 151
FERC ¶ 61,129 (2015)
2
2a
5(i)
Date
FERC’s Order approving the
interpretation of R1 and R3 is
effective as of September 26,
2011
Page 14 of 37
PRC‐004‐5.1(i) – Application Guideline
Guidelines and Technical Basis
Introduction
This standard addresses the reliability issues identified in the letter3 from Gerry Cauley, NERC
President and CEO, dated January 7, 2011.
“Nearly all major system failures, excluding perhaps those caused by severe
weather, have misoperations of relays or automatic controls as a factor
contributing to the propagation of the failure. …Relays can misoperate, either
operate when not needed or fail to operate when needed, for a number of
reasons. First, the device could experience an internal failure – but this is rare.
Most commonly, relays fail to operate correctly due to incorrect settings,
improper coordination (of timing and set points) with other devices, ineffective
maintenance and testing, or failure of communications channels or power
supplies. Preventable errors can be introduced by field personnel and their
supervisors or more programmatically by the organization.”
The standard also addresses the findings in the 2011 Risk Assessment of Reliability
Performance4; July 2011.
“…a number of multiple outage events were initiated by protection system
Misoperations. These events, which go beyond their design expectations and
operating procedures, represent a tangible threat to reliability. A deeper review
of the root causes of dependent and common mode events, which include three
or more automatic outages, is a high priority for NERC and the industry.”
The State of Reliability 20145 report continued to identify Protection System Misoperations as a
significant contributor to automatic transmission outage severity. The report recommended
completion of the development of PRC‐004‐3 as part of the solution to address Protection
System Misoperations.
Definitions
The Misoperation definition is based on the IEEE/PSRC Working Group I3 “Transmission
Protective Relay System Performance Measuring Methodology6.” Misoperations of a Protection
System include failure to operate, slowness in operating, or operating when not required either
during a Fault or non‐Fault condition.
3 (http://www.nerc.com/pa/Stand/Project%20201005%20Protection%20System%20Misoperations%20DL/20110209130708‐
Cauley%20letter.pdf).
4 “2011 Risk Assessment of Reliability Performance.” NERC. (http://www.nerc.com/files/2011_RARPR_FINAL.pdf. July 2011). Pg.
3.
5 “State of Reliability 2014.” NERC. (http://www.nerc.com/pa/Stand/Pages/RelaibilityCoordinationProject20066.aspx). May
2014. Pg. 18 of 106.
6 “Transmission Protective Relay System Performance Measuring Methodology.” Working Group I3 of Power System Relaying
Committee of IEEE Power Engineering Society. 1999.
Page 15 of 37
PRC‐004‐5.1(i) – Application Guideline
For reference, a “Protection System” is defined in the Glossary of Terms Used in NERC Reliability
Standards (“NERC Glossary”) as:
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.
A BES interrupting device is a BES Element, typically a circuit breaker or circuit switcher that has
the capability to interrupt fault current. Although BES interrupting device mechanisms are not
part of a Protection System, the standard uses the operation of a BES interrupting device by a
Protection System to initiate the review for Misoperation.
The following two definitions are being proposed for inclusion in the NERC Glossary:
Composite Protection System – The total complement of Protection System(s) that function
collectively to protect an Element. Backup protection provided by a different Element’s
Protection System(s) is excluded.
The Composite Protection System definition is based on the principle that an Element’s multiple
layers of protection are intended to function collectively. This definition has been introduced in
this standard and incorporated into the proposed definition of Misoperation to clarify that the
overall performance of an Element’s total complement of protection should be considered
while evaluating an operation.
Composite Protection System – Line Example
The Composite Protection System of the Alpha‐Beta line (Circuit #123) is comprised of current
differential, permissive overreaching transfer trip (POTT), step distance (classic zone 1, zone 2,
and zone 3), instantaneous‐overcurrent, time‐overcurrent, out‐of‐step, and overvoltage
protection. The protection is housed at the Alpha and Beta substations, and includes the
associated relays, communications systems, voltage and current sensing devices, DC supplies,
and control circuitry.
Composite Protection System – Transformer Example
The Composite Protection System of the Alpha transformer (#2) is comprised of internal
differential, overall differential, instantaneous‐overcurrent, and time‐overcurrent protection.
The protection is housed at the Alpha substation, and includes the associated relays, voltage
and current sensing devices, DC supplies, and control circuitry.
Page 16 of 37
PRC‐004‐5.1(i) – Application Guideline
Composite Protection System – Generator Example
The Composite Protection System of the Beta generator (#3) is comprised of generator
differential, overall differential, overcurrent, stator ground, reverse power, volts per hertz, loss‐
of‐field, and undervoltage protection. The protection is housed at the Beta generating plant
and at the Beta substation, and includes the associated relays, voltage and current sensing
devices, DC supplies, and control circuitry.
Composite Protection System – Breaker Failure Example
Breaker failure protection provides backup protection for the breaker, and therefore is part of
the breaker’s Composite Protection System. Considering breaker failure protection to be part of
another Element’s Composite Protection System could lead to an incorrect conclusion that a
breaker failure operation automatically satisfies the “Slow Trip” criteria of the Misoperation
definition.
An example of a correct operation of the breaker’s Composite Protection System is
when the breaker failure relaying tripped because the line relaying operated, but the
breaker failed to clear the Fault. The breaker failure relaying operated because of a
failed trip coil. The failed trip coil caused a Misoperation of the line’s Composite
Protection System.
An example of a correct operation of the breaker’s Composite Protection System is
when the breaker failure relaying tripped because the line relaying operated, but the
breaker failed to clear the Fault. Only the breaker failure relaying operated because of a
failed breaker mechanism. This was not a Misoperation because the breaker mechanism
is not part of the breaker’s Composite Protection System.
An example of an “Unnecessary Trip – During Fault” is when the breaker failure relaying
tripped at the same time as the line relaying during a Fault. The Misoperation was due
to the breaker failure timer being set to zero.
Misoperation – The failure a Composite Protection System to operate as intended for
protection purposes. Any of the following is a Misoperation:
1. Failure to Trip – During Fault – A failure of a Composite Protection System to operate for
a Fault condition for which it is designed. The failure of a Protection System component
is not a Misoperation as long as the performance of the Composite Protection System is
correct.
2. Failure to Trip – Other Than Fault – A failure of a Composite Protection System to
operate for a non‐Fault condition for which it is designed, such as a power swing,
undervoltage, overexcitation, or loss of excitation. The failure of a Protection System
component is not a Misoperation as long as the performance of the Composite
Protection System is correct.
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3. Slow Trip – During Fault – A Composite Protection System operation that is slower than
required for a Fault condition if the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System.
4. Slow Trip – Other Than Fault – A Composite Protection System operation that is slower
than required for a non‐Fault condition, such as a power swing, undervoltage,
overexcitation, or loss of excitation, if the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System.
5. Unnecessary Trip – During Fault – An unnecessary Composite Protection System
operation for a Fault condition on another Element.
6. Unnecessary Trip – Other Than Fault – An unnecessary Composite Protection System
operation for a non‐Fault condition. A Composite Protection System operation that is
caused by personnel during on‐site maintenance, testing, inspection, construction, or
commissioning activities is not a Misoperation.
The Misoperation definition is based on the principle that an Element’s total complement of
protection is intended to operate dependably and securely.
Failure to automatically reclose after a Fault condition is not included as a Misoperation
because reclosing equipment is not included within the definition of Protection System.
A breaker failure operation does not, in itself, constitute a Misoperation.
A remote backup operation resulting from a “Failure to Trip” or a “Slow Trip” does not,
in itself, constitute a Misoperation.
This proposed definition of Misoperation provides additional clarity over the current version. A
Misoperation is the failure of a Composite Protection System to operate as intended for
protection purposes. The definition includes six categories which provide further differentiation
of what constitutes a Misoperation. These categories are discussed in greater detail in the
following sections.
Failure to Trip – During Fault
This category of Misoperation typically results in the Fault condition being cleared by remote
backup Protection System operation.
Example 1a: A failure of a transformer's Composite Protection System to operate for a
transformer Fault is a Misoperation.
Example 1b: A failure of a "primary" transformer relay (or any other component) to
operate for a transformer Fault is not a “Failure to Trip – During Fault” Misoperation as
long as another component of the transformer's Composite Protection System
operated.
Example 1c: A lack of target information does not by itself constitute a Misoperation.
When a high‐speed pilot system does not target because a high‐speed zone element
trips first, it would not in and of itself be a Misoperation.
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Example 1d: A failure of an overall differential relay to operate is not a “Failure to Trip –
During Fault” Misoperation as long as another component such as a generator
differential relay operated.
Example 1e: The Composite Protection System for a bus does not operate during a bus
Fault which results in the operation of all local transformer Protection Systems
connected to that bus and all remote line Protection Systems connected to that bus
isolating the faulted bus from the grid. The operation of the local transformer Protection
Systems and the operation of all remote line Protection Systems correctly provided
backup protection. There is one “Failure to Trip – During Fault” Misoperation of the bus
Composite Protection System.
In analyzing the Protection System for Misoperation, the entity must also consider whether the
“Slow Trip – During Fault” category applies to the operation.
Failure to Trip – Other Than Fault
This category of Misoperation may have resulted in operator intervention. The “Failure to Trip –
Other Than Fault” conditions cited in the definition are examples only, and do not constitute an
all‐inclusive list.
Example 2a: A failure of a generator's Composite Protection System to operate for an
unintentional loss of field condition is a Misoperation.
Example 2b: A failure of an overexcitation relay (or any other component) is not a
"Failure to Trip – Other Than Fault" Misoperation as long as the generator's Composite
Protection System operated as intended isolating the generator from the BES.
In analyzing the Protection System for Misoperation, the entity must also consider whether the
“Slow Trip – Other Than Fault” category applies to the operation.
Slow Trip – During Fault
This category of Misoperation typically results in remote backup Protection System operation
before the Fault is cleared.
Example 3a: A Composite Protection System that is slower than required for a Fault
condition is a Misoperation if the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System. The current
differential element of a multiple function relay failed to operate for a line Fault. The
same relay's time‐overcurrent element operated after a time delay. However, an
adjacent line also operated from a time‐overcurrent element. The faulted line's time‐
overcurrent element was found to be set to trip too slowly.
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Example 3b: A failure of a breaker's Composite Protection System to operate as quickly
as intended to meet the expected critical Fault clearing time for a line Fault in
conjunction with a breaker failure (i.e., stuck breaker) is a Misoperation if it resulted in
an unintended operation of at least one other Element’s Composite Protection System.
If a generating unit’s Composite Protection System operates due to instability caused by
the slow trip of the breaker's Composite Protection System, it is not an “Unnecessary
Trip – During Fault” Misoperation of the generating unit’s Composite Protection System.
This event would be a “Slow Trip – During Fault” Misoperation of the breaker's
Composite Protection System.
Example 3c: A line connected to a generation interconnection station is protected with
two independent high‐speed pilot systems. The Composite Protection System for this
line also includes step distance and time‐overcurrent schemes in addition to the two
pilot systems. During a Fault on this line, the two pilot systems fail to operate and the
time‐overcurrent scheme operates clearing the Fault with no generating units or other
Elements tripping (i.e., no over‐trips). This event is not a Misoperation.
The phrase “slower than required” means the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System. It would be impractical
to provide a precise tolerance in the definition that would be applicable to every type of
Protection System. Rather, the owner(s) reviewing each Protection System operation should
understand whether the speed and outcome of its Protection System operation met their
objective. The intent is not to require documentation of exact Protection System operation
times, but to assure consideration of relay coordination and system stability by the owner(s)
reviewing each Protection System operation.
The phrase “resulted in the operation of any other Composite Protection System” refers to the
need to ensure that relaying operates in the proper or planned sequence (i.e., the primary
relaying for a faulted Element operates before the remote backup relaying for the faulted
Element).
In analyzing the Protection System for Misoperation, the entity must also consider the
“Unnecessary Trip – During Fault” category to determine if an “unnecessary trip” applies to the
Protection System operation of an Element other than the faulted Element.
If a coordination error was at the local terminal (i.e., set too slow), then it was a "Slow Trip,"
category of Misoperation at the local terminal.
Slow Trip – Other Than Fault
The phrase “slower than required” means the duration of its operating time resulted in the
operation of at least one other Element’s Composite Protection System. It would be impractical
to provide a precise tolerance in the definition that would be applicable to every type of
Protection System. Rather, the owner(s) reviewing each Protection System operation should
understand whether the speed and outcome of its Protection System operation met their
objective. The intent is not to require documentation of exact Protection System operation
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times, but to assure consideration of relay coordination and system stability by the owner(s)
reviewing each Protection System operation.
Example 4: A phase to phase fault occurred on the terminals of a generator. The
generator's Composite Protection System and a transmission line's Composite
Protection System both operated in response to the fault. It was found during
subsequent investigation that the generator protection contained an inappropriate time
delay. This caused the transmission line's correctly set overreaching zone of protection
to operate. This was a Misoperation of the generator’s Composite Protection System,
but not of the transmission line’s Composite Protection System.
The “Slow Trip – Other Than Fault” conditions cited in the definition are examples only, and do
not constitute an all‐inclusive list.
Unnecessary Trip – During Fault
An operation of a properly coordinated remote Protection System is not in and of itself a
Misoperation if the Fault has persisted for a sufficient time to allow the correct operation of the
Composite Protection System of the faulted Element to clear the Fault. A BES interrupting
device failure, a “failure to trip” Misoperation, or a “slow trip” Misoperation may result in a
proper remote Protection System operation.
Example 5: An operation of a transformer's Composite Protection System which trips
(i.e., over‐trips) for a properly cleared line Fault is a Misoperation. The Fault is cleared
properly by the faulted equipment's Composite Protection System (i.e., line relaying)
without the need for an external Protection System operation resulting in an
unnecessary trip of the transformer protection; therefore, the transformer Protection
System operation is a Misoperation.
Example 5b: An operation of a line's Composite Protection System which trips (i.e.,
over‐trips) for a properly cleared Fault on a different line is a Misoperation. The Fault is
cleared properly by the faulted line's Composite Protection System (i.e., line relaying);
however, elsewhere in the system, a carrier blocking signal is not transmitted (e.g.,
carrier ON/OFF switch found in OFF position) resulting in the operation of a remote
Protection System, single‐end trip of a non‐faulted line. The operation of the Protection
System for the non‐faulted line is an unnecessary trip during a Fault. Therefore, the non‐
faulted line Protection System operation is an “Unnecessary Trip – During Fault”
Misoperation.
Example 5c: If a coordination error was at the remote terminal (i.e., set too fast), then it
was an "Unnecessary Trip – During Fault" category of Misoperation at the remote
terminal.
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Unnecessary Trip – Other Than Fault
Unnecessary trips for non‐Fault conditions include but are not limited to: power swings,
overexcitation, loss of excitation, frequency excursions, and normal operations.
Example 6a: An operation of a line's Composite Protection System due to a relay failure
during normal operation is a Misoperation.
Example 6b: Tripping a generator by the operation of the loss of field protection during
an off‐nominal frequency condition while the field is intact is a Misoperation assuming
the Composite Protection System was not intended to operate under this condition.
Example 6c: An impedance line relay trip for a power swing that entered the relay’s
characteristic is a Misoperation if the power swing was stable and the relay operated
because power swing blocking was enabled and should have prevented the trip, but did
not.
Example 6d: Tripping a generator operating at normal load by the operation of a reverse
power protection relay due to a relay failure is a Misoperation.
Additionally, an operation that occurs during a non‐Fault condition but was initiated directly by
on‐site (i.e., real‐time) maintenance, testing, inspection, construction, or commissioning is not a
Misoperation.
Example 6e: A BES interrupting device operation that occurs at the remote end of a line
during a non‐Fault condition because a direct transfer trip was initiated by system
maintenance and testing activities at the local end of the line is not a Misoperation
because of the maintenance exclusion in category 6 of the definition of “Misoperation.”
The “on‐site” activities at one location that initiates a trip to another location are included in
this exemption. This includes operation of a Protection System when energizing equipment to
facilitate measurements, such as verification of current circuits as a part of performing
commissioning; however, once the maintenance, testing, inspection, construction, or
commissioning activity associated with the Protection System is complete, the "on‐site"
Misoperation exclusion no longer applies, regardless of the presence of on‐site personnel.
Special Cases
Protection System operations for these cases would not be a Misoperation.
Example 7a: A generator Protection System operation prior to closing the unit
breaker(s) is not a Misoperation provided no in‐service Elements are tripped.
This type of operation is not a Misoperation because the generating unit is not synchronized
and is isolated from the BES. Protection System operations that occur when the protected
Element is out of service and that do not trip any in‐service Elements are not Misoperations.
In some cases where zones of protection overlap, the owner(s) of Elements may decide to allow
a Protection System to operate faster in order to gain better overall Protection System
performance for an Element.
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Example 7b: The high‐side of a transformer connected to a line may be within the zone
of protection of the supplying line’s relaying. In this case, the line relaying is planned to
protect the area of the high‐side of the transformer and into its primary winding. In
order to provide faster protection for the line, the line relaying may be designed and set
to operate without direct coordination (or coordination is waived) with local protection
for Faults on the high‐side of the connected transformer. Therefore, the operation of
the line relaying for a high‐side transformer Fault operated as intended and would not
be a Misoperation.
Below are examples of conditions that would be a Misoperation.
Example7c: A 230 kV shunt capacitor bank was released for operational service. The
capacitor bank trips due to a settings error in the capacitor bank differential relay upon
energization.
Example 7d: A 230/115 kV BES transformer bank trips out when being re‐energized due
to an incorrect operation of the transformer differential relay for inrush after being
released for operational service. Only the high‐side breaker opens since the low‐side
breaker had not yet been closed.
Non-Protective Functions
BES interrupting device operations which are initiated by non‐protective functions, such as
those associated with generator controls, excitation controls, or turbine/boiler controls, static
voltampere‐reactive compensators (SVC), flexible ac transmission systems (FACTS), high‐voltage
dc (HVdc) transmission systems, circuit breaker mechanisms, or other facility control systems
are not operations of a Protection System. The standard is not applicable to non‐protective
functions such as automation (e.g., data collection) or control functions that are embedded
within a Protection System.
Control Functions
The entity must make a determination as to whether the standard is applicable to each
operation of its Protection System in accordance with the provided exclusions in the standard’s
Applicability, see Section 4.2.1. The subject matter experts (SME) developing this standard
recognize that entities use Protection Systems as part of a routine practice to control BES
Elements. This standard is not applicable to operation of protective functions within a
Protection System when intended for controlling a BES Element as a part of an entity’s process
or planned switching sequence. The following are examples of conditions to which this standard
is not applicable:
Example 8a: The reverse power protective function that operates to remove a
generating unit from service using the entity’s normal or routine process.
Example 8b: The reverse power relay enables a permissive trip and the generator
operator trips the unit.
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The standard is not applicable to operation of the protective relay because its operation is
intended as a control function as part of a controlled shutdown sequence for the generator.
However, the standard remains applicable to operation of the reverse power relay when it
operates for conditions not associated with the controlled shutdown sequence, such as a
motoring condition caused by a trip of the prime mover.
The following is another example of a condition to which this standard is not applicable:
Example 8c: Operation of a capacitor bank interrupting device for voltage control using
functions embedded within a microprocessor based relay that is part of a Protection
System.
The above are examples only, and do not constitute an all‐inclusive list to which the standard is
not applicable.
Extenuating Circumstances
In the event of a natural disaster or other extenuating circumstances, the December 20, 2012
Sanction Guidelines of the North American Electric Reliability Corporation, Section 2.8,
Extenuating Circumstances, reads: “In unique extenuating circumstances causing or
contributing to the violation, such as significant natural disasters, NERC or the Regional Entity
may significantly reduce or eliminate Penalties.” The Regional Entities to whom NERC has
delegated authority will consider extenuating circumstances when considering any sanctions in
relation to the timelines outlined in this standard.
The volume of Protection System operations tend to be sporadic. If a high rate of Protection
System operations is not sustained, utilities will have an opportunity to catch up within the 120
day period.
Requirement Time Periods
The time periods within all the Requirements are distinct and separate. The applicable entity in
Requirement R1 has 120 calendar days to identify whether a BES interrupting device operation
is a Misoperation. Once the applicable entity has identified a Misoperation, it has completed its
performance under Requirement R1. Identified Misoperations without an identified cause
become subject to Requirement R4 and any subsequent Requirements as necessary. Identified
Misoperations with an identified cause become subject to Requirement R5 and any subsequent
Requirements as necessary.
In Requirement R2, the applicable entity has 120 calendar days, based on the date of the BES
interrupting device operation, to provide notification to the other Protection System owners
that meet the circumstances in Parts 2.1 and 2.2. For the case of an applicable entity that was
notified (R3), it has the later of 120 calendar days from the date of the BES interrupting device
operation or 60 calendar days of notification to identify whether its Protection System
components caused a Misoperation.
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Once a Misoperation is identified in either Requirement R1 or R3, and the applicable entity did
not identify the cause(s) of the Misoperation, the time period for performing at least one
investigative action every two full calendar quarters begins. The time period(s) in Requirement
R4 resets upon each period. When the applicable entity’s investigative actions identify the
cause of the identified Misoperation or the applicable entity declares that no cause was found,
the applicable entity has completed its performance in Requirement R4.
The time period in Requirement R5 begins when the Misoperation cause is first identified. The
applicable entity is allotted 60 calendar days to perform one of the two activities listed in
Requirement R5 (e.g., CAP or declaration) to complete its performance under Requirement R5.
Requirement R6 time period is determined by the actions and the associated timetable to
complete those actions identified in the CAP. The time periods contained in the CAP may
change from time to time and the applicable entity is required to update the timetable when it
changes.
Time periods provided in the Requirements are intended to provide a reasonable amount of
time to perform each Requirement. Performing activities in the least amount of time facilitates
prompt identification of Misoperations, notification to other Protection System owners,
identification of the cause(s), correction of the cause(s), and that important information is
retained that may be lost due to time.
Requirement R1
This Requirement initiates a review of each BES interrupting device operation to identify
whether or not a Misoperation may have occurred. Since the BES interrupting device owner
typically monitors and tracks device operations, the owner is the logical starting point for
identifying Misoperations of Protection Systems for BES Elements. A review is required when
(1) a BES interrupting device operates that is caused by a Protection System or by manual
intervention in response to a Protection System failure to operate, (2) regardless of whether
the owner owns all or part of the Protection System component(s), and (3) the owner identified
its Protection System component(s) as causing the BES interrupting device operation or was
caused by manual intervention in response to its Protection System failure to operate.
Since most Misoperations result in the operation of one or more BES interrupting devices, these
operations initiate a review to identify any Misoperation. If an Element is manually isolated in
response to a failure to operate, the manual isolation of the Element triggers a review for
Misoperation.
Example R1a: The failure of a loss of field relay on a generating unit where an operator
takes action to isolate the unit.
Manual intervention may indicate a Misoperation has occurred, thus requiring the initiation of
an investigation by the BES interrupting device owner.
For the case where a BES interrupting device did not operate and remote clearing occurs due to
the failure of a Composite Protection System to operate, the BES interrupting device owner
would still review the operation under Requirement R1. However, if the BES interrupting device
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owner determines that its Protection System component operated as backup protection for a
condition on another entity’s BES Element, the owner would provide notification of the
operation to the other Protection System owner(s) under Requirement R2, Part 2.2.
Protection Systems are made of many components. These components may be owned by
different entities. For example, a Generator Owner may own a current transformer that sends
information to a Transmission Owner’s differential relay. All of these components and many
more are part of a Protection System. It is expected that all of the owners will communicate
with each other, sharing information freely, so that Protection System operations can be
analyzed, Misoperations identified, and corrective actions taken.
Each entity is expected to use judgment to identify those Protection System operations that
meet the definition of Misoperation regardless of the level of ownership. A combination of
available information from resources such as counters, relay targets, Supervisory Control and
Data Acquisition (SCADA) systems, or DME would typically be used to determine whether or not
a Misoperation occurred. The intent of the standard is to classify an operation as a
Misoperation if the available information leads to that conclusion. In many cases, it will not be
necessary to leverage all available data to determine whether or not a Misoperation occurred.
The standard also allows an entity to classify an operation as a Misoperation if entity is not
sure. The entity may decide to identify the operation as a Misoperation to satisfy Requirement
R1 and continue its investigation for a cause of the Misoperation under Requirement R4. If the
continued investigative actions are inconclusive, the entity may declare no cause found and end
its investigation. The entity is allotted 120 calendar days from the date of its BES interrupting
device operation to identify whether its Protection System component(s) caused a
Misoperation.
The Protection System operation may be documented in a variety of ways such as in a report,
database, spreadsheet, or list. The documentation may be organized in a variety of ways such
as by BES interrupting device, protected Element, or Composite Protection System.
Repeated operations which occur during the same automatic reclosing sequence do not need a
separate identification under Requirement R1. Repeated Misoperations which occur during the
same 24‐hour period do not need a separate identification under Requirement R1. This is
consistent with the NERC Misoperations Report7 which states:
“In order to avoid skewing the data with these repeated events, the NERC SPCS should
clarify, in the next annual update of the misoperation template, that all misoperations
due to the same equipment and cause within a 24 hour period be recorded as one
misoperation.”
The following is an example of a condition that is not a Misoperation.
7 “Misoperations Report.” Reporting Multiple Occurrences. NERC Protection System Misoperations Task Force.
(http://www.nerc.com/docs/pc/psmtf/PSMTF_Report.pdf). April 1, 2013. Pg. 37 of 40.
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Example R1b: A high impedance Fault occurs within a transformer. The sudden pressure
relaying detects and operates for the Fault, but the differential relaying did not operate
due to the low Fault current levels. This is not a Misoperation because the Composite
Protection System was not required to operate because the Fault was cleared by the
sudden pressure relay.
Requirement R2
Requirement R2 ensures notification of those who have a role in identifying Misoperations, but
were not accounted for within Requirement R1. In the case of multi‐entity ownership, the
entity that owns the BES interrupting device that operated is expected to use judgment to
identify those Protection System operations that meet the definition of Misoperation under
Requirement R1; however, if the entity that owns a BES interrupting device determines that its
Protection System component(s) did not cause the BES interrupting device(s) operation or
cannot determine whether its Protection System components caused the BES interrupting
device(s) operation, it must notify the other Protection System owner(s) that share
Misoperation identification responsibility when the criteria in Requirement R2 is met.
This Requirement does not preclude the Protection System owners from initially
communicating and working together to determine whether a Misoperation occurred and, if so,
the cause. The BES interrupting device owner is only required to officially notify the other
owners when it: (1) shares the Composite Protection System ownership with other entity(ies),
(2) determines that a Misoperation occurred or cannot rule out a Misoperation, and (3)
determines its Protection System component(s) did not cause a Misoperation or is unsure.
Officially notifying the other owners without performing a preliminary review may
unnecessarily burden the other owners with compliance obligations under Requirement R3,
redirect valuable resources, and add little benefit to reliability. The BES interrupting device
owner should officially notify other owners when appropriate within the established time
period.
The following is an example of a notification to another Protection System owner:
Example R2a: Circuit breakers A and B at the Charlie station tripped from directional
comparison blocking (DCB) relaying on 03/03/2014 at 15:43 UTC during an external
Fault. As discussed last week, the fault records indicate that a problem with your
equipment (failure to transmit) caused the operation.
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Example R2b: A generator unit tripped out immediately upon synchronizing to the grid
due to a Misoperation of its overcurrent protection. The Transmission Owner owns the
230 kV generator breaker that operated. The Transmission Owner, as the owner of the
BES interrupting device after determining that its Protection System components did
not cause the Misoperation, notified the Generator Owner of the operation. The
Generator Owner investigated and determined that its Protection System components
caused the Misoperation. In this example, the Generator Owner’s Protection System
components did cause the Misoperation. As the owner of the Protection System
components that caused the Misoperation, the Generator Owner is responsible for
creating and implementing the CAP.
A Composite Protection System owned by different functional entities within the same
registered entity does not necessarily satisfy the notification criteria in Part 2.1.1 of
Requirement R2. For example, if the same personnel within a registered entity perform the
Misoperation identification for both the Generator Owner and Transmission Owner functions,
then the Misoperation identification would be completely covered in Requirement R1, and
therefore notification would not be required. However, if the Misoperation identification is
handled by different groups, then notification would be required because the Misoperation
identification would not necessarily be covered in Requirement R1.
Example R2c: Line A Composite Protection System (owned by entity 1) failed to operate
for an internal Fault. As a result, the zone 3 portion of Line B’s Composite Protection
System (owned by entity 2) and zone 3 portion of Line C’s Composite Protection System
(owned by entity 3) operated to clear the Fault. Entity 2 and 3 notified entity 1 of the
remote zone 3 operation.
For the case where a BES interrupting device operates to provide backup protection for a non‐
BES Element, the entity reviewing the operation is not required to notify the other owners of
Protection Systems for non‐BES Elements. No notification is required because this Reliability
Standard is not applicable to Protection Systems for non‐BES Elements.
Requirement R3
For Requirement R3 (i.e., notification received), the entity that also owns a portion of the
Composite Protection System is expected to use judgment to identify whether the Protection
System operation is a Misoperation. A combination of available information from resources
such as counters, relay targets, SCADA, DME, and information from the other owner(s) would
typically be used to determine whether or not a Misoperation occurred. The intent of the
standard is to classify an operation as a Misoperation if the available information leads to that
conclusion. In many cases, it will not be necessary to leverage all available data to determine
whether or not a Misoperation occurred. The standard also allows an entity to classify an
operation as a Misoperation if an entity is not sure. The entity may decide to identify the
operation as a Misoperation to satisfy Requirement R1 and continue its investigation for a
cause of the Misoperation under Requirement R4. If the continued investigative actions are
inconclusive, the entity may declare no cause found and end its investigation.
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The entity that is notified by the BES interrupting device owner is allotted the later of 60
calendar days from receipt of notification or 120 calendar days from the BES interrupting device
operation date to determine if its portion of the Composite Protection System caused the
Protection System operation. It is expected that in most cases of a jointly owned Protection
System, the entity making notification would have been in communication with the other
owner(s) early in the process. This means that the shorter 60 calendar days only comes into
play if the notification occurs in the second half of the 120 calendar days allotted to the BES
interrupting device owner in Requirement R1.
The Protection System review may be organized in a variety of ways such as in a report,
database, spreadsheet, or list. The documentation may be organized in a variety of ways such
as by BES interrupting device, protected Element, or Composite Protection System. The BES
interrupting device owner’s notification received may be documented in a variety of ways such
as an email or a facsimile.
Requirement R4
The entity in Requirement R4 (i.e., cause identification), whether it is the entity that owns the
BES interrupting device or an entity that was notified, is expected to use due diligence in taking
investigative action(s) to determine the cause(s) of an identified Misoperation for its portion of
the Composite Protection System. The SMEs developing this standard recognize there will be
cases where the cause(s) of a Misoperation will not be revealed during the allotted time periods
in Requirements R1 or R3; therefore, Requirement R4 provides the entity a mechanism to
continue its investigative work to determine the cause(s) of the Misoperation when the cause is
not known.
A combination of available information from resources such as counters, relay targets, SCADA,
DME, test results, and studies would typically be used to determine the cause of the
Misoperation. At least one investigative action must be performed every two full calendar
quarters until the investigation is completed.
The following is an example of investigative actions taken to determine the cause of an
identified Misoperation:
Example R4a: A Misoperation was identified on 03/18/2014. A line outage to test the
Protection System was scheduled on 03/24/2014 for 12/15/2014 as the first
investigative action (i.e., beyond the next two full calendar quarters) due to summer
peak conditions. The protection engineer contacted the manufacturer on 04/10/2014
(i.e., within two full calendar quarters) to obtain any known issues. The engineer
reviewed manufacturer’s documents on 05/27/2014. The outage schedule was
confirmed on 08/29/2014 and was taken on 12/15/2014. Testing was completed on
12/16/2014 (i.e., in the second two full quarters) revealing the microprocessor relay as
the cause of the Misoperation. A CAP is being developed to replace the relay.
Periodic action minimizes compliance burdens and focuses the entity’s effort on determining
the cause(s) of the Misoperation while providing measurable evidence. The SMEs recognize
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PRC‐004‐5.1(i) – Application Guideline
that certain planned investigative actions may require months or years to schedule and
complete; therefore, the entity is only required to perform at least one investigative action
every two full calendar quarters. If an investigative action is performed in the first quarter of a
calendar year, the next investigative action would need to be performed by the end of the third
calendar quarter. If an investigative action is performed in the last quarter of a calendar year,
the next investigative action would need to be performed by the end of the second calendar
quarter of the following calendar year. Investigative actions may include a variety of actions,
such as reviewing DME records, performing or reviewing studies, completing relay calibration
or testing, requesting manufacturer review, requesting an outage, or confirming a schedule.
The entity’s investigation is complete when it identifies the cause of the Misoperation or makes
a declaration that no cause was determined. The declaration is intended to be used if the entity
determines that investigative actions have been exhausted or have not provided direction for
identifying the Misoperation cause. Historically, approximately 12% of Misoperations are
unknown or unexplainable.8
Although the entity only has to document its specific investigative actions taken to determine
the cause(s) of an identified Misoperation, the entity should consider the benefits of formally
organizing (e.g., in a report or database) its actions and findings. Well documented investigative
actions and findings may be helpful in future investigations of a similar event or circumstances.
A thorough report or database may contain a detailed description of the event, information
gathered, investigative actions, findings, possible causes, identified causes, and conclusions.
Multiple owners of a Composite Protection System might consider working together to produce
a common report for their mutual benefit.
The following are examples of a declaration where no cause was determined:
Example R4b: A Misoperation was identified on 04/11/2014. All relays at station A and B
functioned properly during testing on 08/26/2014 as the first investigative action. The
carrier system functioned properly during testing on 08/27/2014. The carrier coupling
equipment functioned properly during testing on 08/28/2014. A settings review
completed on 09/03/2014 indicated the relay settings were proper. Since the
equipment involved in the operation functioned properly during testing, the settings
were reviewed and found to be correct, and the equipment at station A and station B is
already monitored. The investigation is being closed because no cause was found.
Example R4c: A Misoperation was identified on 03/22/2014. The protection scheme was
replaced before the cause was identified. The power line carrier or PLC based protection
was replaced with fiber‐optic based protection with an in‐service date of 04/16/2014.
The new system will be monitored for recurrence of the Misoperation.
8 NERC System Protection and Control Subcommittee. Misoperations Report. April 1, 2013. (http://www.nerc.com/docs/pc/
psmtf/PSMTF_Report.pdf). Figure 15: NERC Wide Misoperations by Cause Code. Pg. 22 of 40.
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PRC‐004‐5.1(i) – Application Guideline
Requirement R5
Resolving the causes of Protection System Misoperations benefits BES reliability by preventing
recurrence. The Corrective Action Plan (CAP) is an established tool for resolving operational
problems. The NERC Glossary defines a Corrective Action Plan as, "A list of actions and an
associated timetable for implementation to remedy a specific problem." Since a CAP addresses
specific problems, the determination of what went wrong needs to be completed before
developing a CAP. When the Misoperation cause is identified in Requirement R1, R3 or R4,
Requirement R5 requires Protection System owner(s) to develop a CAP, or explain why
corrective actions are beyond the entity’s control or would not improve BES reliability. The
entity must develop the CAP or make a declaration why additional actions are beyond the
entity’s control or would not improve BES reliability and that no further corrective actions will
be taken within 60 calendar days of first determining a cause.
The SMEs developing this standard recognize there may be multiple causes for a Misoperation.
In these circumstances, the CAP would include a remedy for the identified causes. The CAP may
be revised if additional causes are found; therefore, the entity has the option to create a single
or multiple CAP(s) to correct multiple causes of a Misoperation. The 60 calendar day period for
developing a CAP (or declaration) is established on the basis of industry experience which
includes operational coordination timeframes, time to consider alternative solutions,
coordination of resources, and development of a schedule.
The development of a CAP is intended to document the specific corrective actions needed to be
taken to prevent Misoperation recurrence, the timetable for executing such actions, and an
evaluation of the CAP's applicability to the entity’s other Protection Systems including other
locations. The evaluation of these other Protection Systems aims to reduce the risk and
likelihood of similar Misoperations in other Protection Systems. The Protection System owner is
responsible for determining the extent of its evaluation concerning other Protection Systems
and locations. The evaluation may result in the owner including actions to address Protection
Systems at other locations or the reasoning for not taking any action. The CAP and an
evaluation of other Protection Systems including other locations must be developed to
complete Requirement R5.
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined capacitor replacement was not necessary.
For completion of each CAP in Examples R5a through R5d, please see Examples R6a through
R6d.
Example R5a: Actions: Remove the relay from service. Replace capacitor in the relay.
Test the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay has not been
experiencing problems and is systematically being replaced with microprocessor relays
as Protection Systems are modernized. Therefore, it was assessed that a program for
wholesale preemptive replacement of capacitors in this type of impedance relay does
not need to be established for the system.
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PRC‐004‐5.1(i) – Application Guideline
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined the capacitors need preemptive correction action.
Example R5b: Actions: Remove the relay from service. Replace capacitor in the relay.
Test the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay is suspected to
have previously tripped at other locations because of the same type of capacitor issue.
Based on the evaluation, a program should be established by 12/01/2014 for wholesale
preemptive replacement of capacitors in this type of impedance relay.
The following is an example of a CAP for a relay Misoperation that was applying a standing trip
due to a failed capacitor within the relay and the evaluation of the cause at similar locations
which determined the capacitors need preemptive correction action.
Example R5c: Actions: Remove the relay from service. Replace capacitor in the relay.
Test the relay. Return to service or replace by 07/01/2014.
Applicability to other Protection Systems: This type of impedance relay is suspected to
have previously tripped at other locations because of the same type of capacitor issue.
Based on the evaluation, the preemptive replacement of capacitors in this type of
impedance relay should be pursued for the identified stations A through I by
04/30/2015.
A plan is being developed to replace the impedance relay capacitors at stations A, B, and
C by 09/01/2014. A second plan is being developed to replace the impedance relay
capacitors at stations D, E, and F by 11/01/2014. The last plan will replace the
impedance relay capacitors at stations G, H, and I by 02/01/2015.
The following is an example of a CAP for a relay Misoperation that was due to a version 2
firmware problem and the evaluation of the cause at similar locations which determined the
firmware needs preemptive correction action.
Example R5d: Actions: Provide the manufacturer fault records. Install new firmware
pending manufacturer results by 10/01/2014.
Applicability to other Protection Systems: Based on the evaluation of other locations
and a risk assessment, the newer firmware version 3 should be installed at all
installations that are identified to be version 2. Twelve relays were identified across the
system. Proposed completion date is 12/31/2014.
The following are examples of a declaration made where corrective actions are beyond the
entity’s control or would not improve BES reliability and that no further corrective actions will
be taken.
Example R5e: The cause of the Misoperation was due to a non‐registered entity
communications provider problem.
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PRC‐004‐5.1(i) – Application Guideline
Example R5f: The cause of the Misoperation was due to a transmission transformer
tapped industrial customer who initiated a direct transfer trip to a registered entity’s
transmission breaker.
In situations where a Misoperation cause emanates from a non‐registered outside entity, there
may be limited influence an entity can exert on an outside entity and is considered outside of
an entity’s control.
The following are examples of declarations made why corrective actions would not improve BES
reliability.
Example R5g: The investigation showed that the Misoperation occurred due to
transients associated with energizing transformer ABC at Station Y. Studies show that
de‐sensitizing the relay to the recorded transients may cause the relay to fail to operate
as intended during power system oscillations.
Example R5h: As a result of an operation that left a portion of the power system in an
electrical island condition, circuit XYZ within that island tripped, resulting in loss of load
within the island. Subsequent investigation showed an overfrequency condition
persisted after the formation of that island and the XYZ line protective relay operated.
Since this relay was operating outside of its designed frequency range and would not be
subject to this condition when line XYZ is operated normally connected to the BES, no
corrective action will be taken because BES reliability would not be improved.
Example R5i: During a major ice storm, four of six circuits were lost at Station A.
Subsequent to the loss of these circuits, a skywire (i.e., shield wire) broke near station A
on line AB (between Station A and B) resulting in a phase‐phase Fault. The protection
scheme utilized for both protection groups is a permissive overreaching transfer trip
(POTT). The Line AB protection at Station B tripped timed for this event (i.e., Slow Trip –
During Fault) even though this line had been identified as requiring high speed clearing.
A weak infeed condition was created at Station A due to the loss of 4 transmission
circuits resulting in the absence of a permissive signal on Line AB from Station A during
this Fault. No corrective action will be taken for this Misoperation as even under N‐1
conditions, there is normally enough infeed at Station A to send a proper permissive
signal to station B. Any changes to the protection scheme to account for this would not
improve BES reliability.
A declaration why corrective actions are beyond the entity’s control or would not improve BES
reliability should include the Misoperation cause and the justification for taking no corrective
action. Furthermore, a declaration that no further corrective actions will be taken is expected
to be used sparingly.
Requirement R6
To achieve the stated purpose of this standard, which is to identify and correct the causes of
Misoperations of Protection Systems for BES Elements, the responsible entity is required to
implement a CAP that addresses the specific problem (i.e., cause(s) of the Misoperation)
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PRC‐004‐5.1(i) – Application Guideline
through completion. Protection System owners are required in the implementation of a CAP to
update it when actions or timetable change, until completed. Accomplishing this objective is
intended to reduce the occurrence of future Misoperations of a similar nature, thereby
improving reliability and minimizing risk to the BES.
The following is an example of a completed CAP for a relay Misoperation that was applying a
standing trip (See also, Example R5a).
Example R6a: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the
impedance relay and replaced. The impedance relay functioned properly during testing
after the capacitor was replaced. The impedance relay was returned to service on
06/05/2014.
CAP completed on 06/25/2014.
The following is an example of a completed CAP for a relay Misoperation that was applying a
standing trip that resulted in the correction and the establishment of a program for further
replacements (See also, Example R5b).
Example R6b: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the
impedance relay and replaced. The impedance relay functioned properly during testing
after the capacitor was replaced. The impedance relay was returned to service on
06/05/2014.
A program for wholesale preemptive replacement of capacitors in this type of
impedance relay was established on 10/28/2014.
CAP completed on 10/28/2014.
The following is an example of a completed CAP of corrective actions with a timetable that
required updating for a failed relay and preemptive actions for similar installations (See also,
Example R5c).
Example R6c: Actions: The impedance relay was removed from service on 06/02/2014
because it was applying a standing trip. A failed capacitor was found within the
impedance relay and replaced. The impedance relay functioned properly during testing
after the capacitor was replaced. The impedance relay was returned to service on
06/05/2014.
The impedance relay capacitor replacement was completed at stations A, B, and C on
08/16/2014. The impedance relay capacitor replacement was completed at stations D,
E, and F on 10/24/2014. The impedance relay capacitor replacement for stations G, H,
and I were postponed due to resource rescheduling from a scheduled 02/01/15
completion to 04/01/2015 completion. Capacitor replacement was completed on
03/09/2015 at stations G, H, and I. All stations identified in the evaluation have been
completed.
CAP completed on 03/09/2015.
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PRC‐004‐5.1(i) – Application Guideline
The following is an example of a completed CAP for corrective actions with updated actions for
a firmware problem and preemptive actions for similar installations. (See also, Example R5d).
Example R6d: Actions: fault records were provided to the manufacturer on 06/04/2014.
The manufacturer responded that the Misoperation was caused by a bug in version 2
firmware, and recommended installing version 3 firmware. Version 3 firmware was
installed on 08/12/2014.
Nine of the twelve relays were updated to version 3 firmware on 09/23/2014. The
manufacturer provided a subsequent update which was determined to be beneficial for
the remaining relays. The remaining three of twelve relays identified as having the
version 2 firmware were updated to version 3.01 firmware on 11/10/2014.
CAP completed on 11/10/2014.
The CAP is complete when all of the actions identified within the CAP have been completed.
Process Flow Chart: Below is a graphical representation demonstrating the relationships
between Requirements:
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PRC‐004‐5.1(i) – Application Guideline
Entry Point(s)
(Notified Entities)
(2.1) The owner of a BES interrupting device
that operated, within 120 calendar days of
the BES interrupting device operation
BES interrupting device owner
The owner of a BES interrupting device that operated, within 120
calendar days of the BES interrupting device operation
Operation was caused
by a Protection System
or by manual
intervention in
response to a
Protection System
failure to operate
BES interrupting
device owner
owns all or part
of the Protection
System
component(s)
BES interrupting device owner must
also consider this as a parallel path if a
Composite Protection System has multiple owners
BES interrupting device
owner identified that its
Protection System
component(s) caused the
BES interrupting device(s)
operation or by manual
intervention
BES
interrupting
device owner
shares the
Composite
Protection
System
ownership
with other
entity(ies)
BES
BES interrupting
interrupting
device owner
device owner
determined
determined
that its
that a
Protection
Misoperation
System
occurred or
component(s)
cannot rule
did not cause
out a
the operation
Misoperation
or is unsure
When
all are
TRUE
R2
R1
The entity that receives notification, within the later of
either 60 calendar days of notification or 120 calendar
days of the BES interrupting device(s) operation, shall
identify whether its Protection System component(s)
caused a Misoperation.
R3
Is a
Misop?
NO
YES
(2.2)
Shall notify the other
owner(s) of the Protection
System of the BES
interrupting device
operation
When
all are
TRUE
Shall identify whether BES interrupting device owner’s Protection
System component(s) caused a Misoperation
Remote
Backup
Protection
Operated?
NO
The entity that owns the Protection System component that caused
the Misoperation, within 60 calendar days of first identifying a cause
YES
Stop
Cause
Known?
Corrective
actions are beyond the
entity’s control or would
not improve BES
reliability?
YES
NO
R5
An entity that has not determined the cause(s) of a Misoperation
shall perform at least one investigative action to determine the
cause(s) of the Misoperation, at least once every two full calendar
quarters after the Misoperation was first identified, until one of the
following completes the investigation:
R4
NO
Cause
Found?
YES
NO
Develop a CAP and
an evaluation
Stop
Implement each Corrective
Action Plan (CAP), and update
each CAP if actions or
timetables change, until
completed.
Stop
Write a
declaration
that no cause
was identified
YES
Cause
identified
R6
Document why
corrective actions are
beyond the entity’s
control or would not
improve BES reliability,
and that no further
corrective actions will
be taken
Stop
YES
CAP
complete?
NO
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PRC‐004‐5.1 – Supplemental Information
Rationale
During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for Introduction
The only revisions made to version of PRC‐004‐4 are revisions to section 4.2 Facilities to clarify
applicability of the Requirements of the standard at generator Facilities. These applicability
revisions are intended to clarify and provide for consistent application of the Requirements to
BES generator Facilities included in the BES through Inclusion I4 – Dispersed Power Producing
Resources.
Rationale for Applicability
Misoperations occurring on the Protection Systems of individual generation resources
identified under Inclusion I4 of the BES definition do not have a material impact on BES
reliability when considered individually; however, the aggregate capability of these resources
may impact BES reliability if a number of Protection Systems on the individual power producing
resources incorrectly operated or failed to operate as designed during a system event. To
recognize the potential for the Protection Systems of individual power producing resources to
affect the reliability of the BES, 4.2.1.5 of the Facilities section reflects the threshold consistent
with the revised BES definition. See FERC Order Approving Revised Definition, P 20, Docket No.
RD14‐2‐000. The intent of 4.2.1.5 of the Facilities section is to exclude from the standard
requirements these Protection Systems for “common‐ mode failure” type scenarios affecting
less than or equal to 75 MVA aggregated nameplate generating capability at these dispersed
generating facilities.
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| File Type | application/pdf |
| File Modified | 2015-07-02 |
| File Created | 2015-07-02 |