Download:
pdf |
pdfRegional Reliability Standard Name:
Regional Reliability Standard No:
NPCC Tracking Number:
Disturbance Monitoring
PRC-002-NPCC-01
NPCC
QR
BOT
SAR – Standard Authorization Request Attachment A
File Name: RSAR--Revise_or_Retire----PRC-002-NPCC-01--2-19-15
Regional Reliability Standard(s) (clean as approved) Attachment B
File Name: PRC-002-NPCC-01
Regional Reliability Standard(s) (clean as proposed) Attachment B1
File Name: NA
Regional Reliability Standard(s) (redlined) Attachment C
File Name: NA
Project Roadmap Attachment D
File Name: NA
Implementation Plan Attachment E
File Name: NA
Technical Justification Attachment F
File Name: PRC-002-NPCC-01 Disturbance Monitoring Technical Justification
VRF & VSL Justification Attachment G
File Name: NA
Issue Table and Mapping Document – Optional Attachment G1
File Name: NA
Regional Reliability Standard Submittal Request Attachment H
File Name: NA
Order 672 Criteria Attachment I
File Name: NA
Drafting Team Roster with Biographies Attachment J
File Name: PRC-002-NPCC-02 Drafting Team Roster
Ballot Pool Results and Ballot Pool Members Attachment K
File Name: PRC-002-NPCC-01 Disturbance Monitoring Ballot Announcement and Results
Guidance Document- Optional Attachment L
File Name: NA
Gov’t.Auth.*
Minority Issues Attachment M
File Name: NA
NPCC Standards Committee Roster Attachment N
File Name: RSC Roster
FERC Issues Table Optional Attachment O
File Name: NA
Additional Supporting Documentation Optional Attachment P and
Q
File Name: NA
Responses to Comments – NPCC Attachment R1
File Name: NA
Responses to Comments – NPCC Attachment R2
File Name: NA
Responses to Comments – NERC Attachment R3
File Name: NA
The following is for NERC completion.
Petition Filing (Federal Energy Regulatory Commission)
File Name:
*Applicable governmental authorities in the United States, Canada, and Mexico
To be provided by NERC.
The above documents have been provided to NERC in MS Word format.
Information in a Regional Standard Authorization
Request (RSAR)
The tables below identify information to be submitted in a Regional Standard
Authorization Request to the NPCC Regional Standards Process Manager,
[email protected] . The NPCC Regional Standards Process Manager shall be
responsible for implementing and maintaining this form as needed to support the
information requirements of the standards process.
Regional Standard Authorization Request Form
Title of Proposed Standard :
PRC-002-NPCC-02
Request Date:
02-18-2015
RSAR Requester Information
RSAR Type (Check box for one of these
selections.)
Name:
Paul DiFilippo
Company:
NPCC
New Standard
Telephone:
416-345-5042
Revision to Existing Standard
Fax:
Email:
Withdrawal of Existing Standard
[email protected]
Urgent Action
Purpose (Describe the purpose of the proposed standard – what the standard will achieve in
support of reliability.)
The purpose of the proposed RSAR is to review the regional standard for potential revisions
made necessary by the industry’s adoption of the new NERC BES definition, the Paragraph 81
directive, and the development of NERC’s PRC-002-2 Disturbance Monitoring and Reporting
Requirements standard. Retiring PRC-002-NPCC-01 is to be considered if it is determined that
it can be retired without sacrificing the ability to capture post-disturbance data.
Industry Need (Provide a detailed statement justifying the need for the proposed standard, along
with any supporting documentation.)
To enhance efficiencies and cost effectiveness, it must be determined if
PRC-002-NPCC-01requirements should be revised or retired to address the new NERC BES
definition, to incorporate Paragraph 81, and to eliminate redundancy leading to double jeopardy
with PRC-002-2 requirements without sacrificing the ability to capture post-disturbance data.
Brief Description (Describe the proposed standard in sufficient detail to clearly define the scope
in a manner that can be easily understood by others.)
The requirements in PRC-002-NPCC-01 will be reviewed individually for revision or deletion
with respect to the new NERC BES definition and Paragraph 81. In addition, PRC-002-NPCC01 will be reviewed against NERC’s PRC-002-2. PRC-002-2 mandates the capturing of
adequate data to facilitate the analysis of BES disturbances. This “umbrella” encompasses the
relevant requirements in PRC-002-NPCC-01. However, the relevant requirements in each of the
standards are to be compared and the requirements of PRC-002-NPCC-01, if so determined, will
be revised or deleted to eliminate redundancy and the concomitant double jeopardy. The review
will be governed by bullet 1 of the NERC Rules of Procedure, Section 312, Regional Reliability
Standards, which reads “Regional Entities may propose Regional Reliability Standards that set
more stringent reliability requirements than the NERC Reliability Standard or cover matters not
covered by an existing NERC Reliability Standard.”
After this review is completed, it will be determined if PRC-002-NPCC-01 should be revised, or
retired.
Reliability Functions
The Standard will Apply to the Following Functions (Check all applicable boxes.)
Reliability
Coordinator
The entity that is the highest level of authority who is responsible for the
reliable operation of the Bulk Electric System, has the Wide Area view of
the Bulk Electric System, and has the operating tools, processes and
procedures, including the authority to prevent or mitigate emergency
operating situations in both next-day analysis and real-time operations.
The Reliability Coordinator has the purview that is broad enough to enable
the calculation of Interconnection Reliability Operating Limits, which may
be based on the operating parameters of transmission systems beyond any
Transmission Operator’s vision.
Balancing
Authority
The responsible entity that integrates resource plans ahead of time,
maintains load-interchange-generation balance within a Balancing
Authority Area, and supports Interconnection frequency in real time.
Interchange
Authority
Authorizes valid and balanced Interchange Schedules.
Planning
Authority
The responsible entity that coordinates and integrates transmission facility
and service plans, resource plans, and protection systems.
Transmission The entity that administers the transmission tariff and provides
Service
Transmission Service to Transmission Customers under applicable
Provider
transmission service agreements.
Transmission The entity that owns and maintains transmission facilities.
Owner
Transmission The entity responsible for the reliability of its “local” transmission system,
Operator
and that operates or directs the operations of the transmission facilities.
Transmission The entity that develops a long-term (generally one year and beyond) plan
Planner
for the reliability (adequacy) of the interconnected bulk electric
transmission systems within its portion of the Planning Authority Area.
Resource
Planner
The entity that develops a long-term (generally one year and beyond) plan
for the resource adequacy of specific loads (customer demand and energy
requirements) within a Planning Authority Area.
Generator
Operator
The entity that operates generating unit(s) and performs the functions of
supplying energy and Interconnected Operations Services.
Generator
Owner
Entity that owns and maintains generating units.
PurchasingSelling
Entity
The entity that purchases or sells, and takes title to, energy, capacity, and
Interconnected Operations Services. Purchasing-Selling Entities may be
affiliated or unaffiliated merchants and may or may not own generating
facilities.
Distribution
Provider
Provides and operates the “wires” between the transmission system and the
customer.
LoadServing
Entity
Secures energy and transmission service (and related Interconnected
Operations Services) to serve the electrical demand and energy
requirements of its end-use customers.
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all boxes 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.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
Recognizing that reliability is an Common Attribute of a robust North American economy:
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
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
Detailed Description (Provide enough detail so that an independent entity familiar with the
industry could draft a standard based on this description.)
Review PRC-002-NPCC-01against PRC-002-2 to determine if revisions are necessary or
retirement of PRC-002-NPCC-01 is possible.
Related Standards
Standard No.
Explanation
PRC-002-2
NERC Disturbance Monitoring and Reporting Requirements standard
Related SARs or RSARs
SAR ID
Explanation
RSAR-11/26/12
RSAR for PRC-002-NPCC-01 to be reviewed with respect to the revised BES
definition (withdrawn).
Standard PRC-002-NPCC-01— Disturbance Monitoring
A. Introduction
1.
Title:
Disturbance Monitoring
2.
Number:
PRC-002-NPCC-01
3.
Purpose:
Ensure that adequate disturbance data is available to facilitate Bulk
Electric System event analyses. All references to equipment and
facilities herein unless otherwise noted will be to Bulk Electric
System (BES) elements.
4.
Applicability:
4.1. Transmission Owner
4.2. Generator Owner
4.3. Reliability Coordinator
5.
(Proposed) Effective Date: To be established.
B. Requirements
R1. Each Transmission Owner and Generator Owner shall provide Sequence of
Event (SOE) recording capability by installing Sequence of Event recorders or
as part of another device, such as a Supervisory Control And Data Acquisition
(SCADA) Remote Terminal Unit (RTU), a generator plant Digital (or
Distributed) Control System (DCS) or part of Fault recording equipment. This
capability shall: [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
1.1 Be provided at all substations and at locations where circuit breaker
operation affects continuity of service to radial Loads greater than
300MW, or the operation of which drops 50MVA Nameplate Rating or
greater of Generation, or the operation of which creates a Generation/Load
island.
Be provided at generating units above 50MVA Nameplate Rating or series
of generating units utilizing a control scheme such that the loss of 1 unit
results in a loss of greater than 50MVA Nameplate Capacity, and at
Generating Plants above 300MVA Name Plate Capacity.
1.2 Monitor the following at each location listed in 1.1:
1.2.1 Transmission and Generator circuit breaker positions
1.2.2 Protective Relay tripping for all Protection Groups that operate to
trip circuit breakers identified in 1.2.1.
1.2.3 Teleprotection keying and receive
Adopted by NERC Board of Trustees: November 4, 2010
1
Standard PRC-002-NPCC-01— Disturbance Monitoring
R2. Each Transmission Owner shall provide Fault recording capability for the following Elements at facilities
where Fault recording equipment is required to be installed as per R3: [Violation Risk Factor: Medium]
[Time Horizon: Planning and Operations Planning]
2.1
All transmission lines.
2.2
Autotransformers or phase-shifters connected to busses.
2.3 Shunt capacitors, shunt reactors.
2.4 Individual generator line interconnections.
2.5 Dynamic VAR Devices.
2.6 HVDC terminals.
R3. Each Transmission Owner shall have Fault recording capability that determines the Current Zero
Time for loss of Bulk Electric System (BES) transmission Elements. [Violation Risk Factor: Medium]
[Time Horizon: Planning and Operations Planning]
R4. Each Generator Owner shall provide Fault recording capability for Generating Plants at and above 200
MVA Capacity and connected through a generator step up (GSU) transformer to a Bulk Electric
System Element unless Fault recording capability is already provided by the Transmission Owner.
[Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
R5. Each Transmission Owner and Generator Owner shall record for Faults, sufficient electrical quantities
for each monitored Element to determine the following: [Violation Risk Factor: Medium] [Time
Horizon: Planning and Operations Planning]
5.1
Three phase-to-neutral voltages. (Common bus-side voltages may be used for lines.)
5.2
Three phase currents and neutral currents.
5.3
Polarizing currents and voltages, if used.
5.4
Frequency.
5.5 Real and reactive power.
R6. Each Transmission Owner and Generator Owner shall provide Fault recording with the following
capabilities: [Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
6.1
Each Fault recorder record duration shall be a minimum of one (1) second.
6.2
Each Fault recorder shall have a minimum recording rate of 16 samples per
6.3
Each Fault recorder shall be set to trigger for at least the following:
cycle
6.3.1 Monitored phase overcurrents set at 1.5 pu or less of rated CT secondary current or
Protective Relay tripping for all Protection Groups.
6.3.2
Neutral (residual) overcurrent set at 0.2 pu or less of rated CT secondary current.
6.3.3 Monitored phase undervoltage set at 0.85 pu or greater.
6.4
R7.
Document additional triggers and deviations from the settings in 6.3.2 and 6.3.3 when local
conditions dictate.
Each Reliability Coordinator shall establish its area’s requirements for Dynamic Disturbance
Recording (DDR) capability that: [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
Adopted by NERC Board of Trustees: November 4, 2010
2
Standard PRC-002-NPCC-01— Disturbance Monitoring
7.1 Provides a minimum of 1 DDR per 3,000 MW of peak Load.
7.2 Records dynamic disturbance information with consideration of the following
facilities/locations:
7.2.1 Major Load centers.
7.2.2 Major Generation clusters.
7.2.3 Major voltage sensitive areas.
7.2.4 Major transmission interfaces.
7.2.5 Major transmission junctions.
7.2.6 Elements associated with Interconnection Reliability Operating Limits (IROLs).
7.2.7 Major EHV interconnections between operating areas.
R8. Each Reliability Coordinator shall specify that DDRs installed, after the approval of this standard,
function as continuous recorders. [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
R9. Each Reliability Coordinator shall specify that DDRs are installed with the following capabilities:
[Violation Risk Factor: Medium] [Time Horizon: Planning and Operations Planning]
9.1
A minimum recording time of sixty (60) seconds per trigger event.
9.2
A minimum data sample rate of 960 samples per second, and a minimum data storage rate for
RMS quantities of six (6) data points per second.
9.3
Each DDR shall be set to trigger for at least one of the following (based on manufacturers’
equipment capabilities):
9.3.1 Rate of change of Frequency.
9.3.2 Rate of change of Power.
9.3.3 Delta Frequency (recommend 20 mHz change).
9.3.4 Oscillation of Frequency.
R10. Each Reliability Coordinator shall establish requirements such that the following quantities are
monitored or derived where DDRs are installed: [Violation Risk Factor: Medium] [Time Horizon:
Planning and Operations Planning]
10.1 Line currents for most lines such that normal line maintenance activities do not interfere with
DDR functionality.
10.2 Bus voltages such that normal bus maintenance activities do not interfere with DDR
functionality.
10.3 As a minimum, one phase current per monitored Element and two phase-to-neutral voltages of
different Elements. One of the monitored voltages shall be of the same phase as the monitored
current.
10.4 Frequency.
10.5 Real and reactive power.
R11. Each Reliability Coordinator shall document additional settings and deviations from the required
trigger settings described in R9 and the required list of monitored quantities as described in R10, and
Adopted by NERC Board of Trustees: November 4, 2010
3
Standard PRC-002-NPCC-01— Disturbance Monitoring
report this to the Regional Entity (RE) upon request. [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning]
R12. Each Reliability Coordinator shall specify its DDR requirements including the DDR setting triggers
established in R9 to the Transmission Owners and Generator Owners. [Violation Risk Factor:
Medium] [Time Horizon: Planning and Operations Planning]
R13. Each Transmission Owner and Generator Owner that receives a request from the Reliability
Coordinator to install a DDR shall acquire and install the DDR in accordance with R12. Reliability
Coordinators, Transmission Owners, and Generator Owners shall mutually agree on an
implementation schedule. [Violation Risk Factor: Medium] [Time Horizon: Planning and
Operations Planning]
R14. Each Transmission Owner and Generator Owner shall establish a maintenance and testing program for
stand alone DME (equipment whose only purpose is disturbance monitoring) that includes: [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning]
14.1 Maintenance and testing intervals and their basis.
14.2 Summary of maintenance and testing procedures.
14.3 Monthly verification of communication channels used for accessing records remotely (if the
entity relies on remote access and the channel is not monitored to a control center staffed around
the clock, 24 hours a day, 7 days a week (24/7)).
14.4 Monthly verification of time synchronization (if the loss of time synchronization is not
monitored to a 24/7 control center).
14.5 Monthly verification of active analog quantities.
14.6 Verification of DDR and DFR settings in the software every six (6) years.
14.7 A requirement to return failed units to service within 90 days. If a DME device will be out of
service for greater than 90 days the owner shall keep a record of efforts aimed at restoring the
DME to service.
R15. Each Reliability Coordinator, Transmission Owner and Generator Owner shall share data within 30
days upon request. Each Reliability Coordinator, Transmission Owner, and Generator Owner shall
provide recorded disturbance data from DMEs within 30 days of receipt of the request in each of the
following cases: [Violation Risk Factor: Lower] [Time Horizon: Operations]
15.1 NERC, Regional Entity, Reliability Coordinator.
15.2 Request from other Transmission Owners, Generator Owners within NPCC.
R16. Each Reliability Coordinator, Transmission Owner and Generator Owner shall submit the data files
conforming to the following format requirements: [Violation Risk Factor: Lower] [Time Horizon:
Operations]
16.1 The data files shall be capable of being viewed, read, and analyzed with a generic COMTRADE
analysis tool as per the latest revision of IEEE Standard C37.111.
16.2 Disturbance Data files shall be named in conformance with the latest revision of IEEE Standard
C37.232.
16.3 Fault Recorder and DDR Files shall contain all monitored channels. SOE records shall contain
station name, date, time resolved to milliseconds, SOE point name, status.
Adopted by NERC Board of Trustees: November 4, 2010
4
Standard PRC-002-NPCC-01— Disturbance Monitoring
R17. Each Reliability Coordinator, Transmission Owner and Generator Owner shall maintain, record and
provide to the Regional Entity (RE), upon request, the following data on the DMEs installed to meet
this standard: [Violation Risk Factor: Lower] [Time Horizon: Operations]
17.1 Type of DME.
17.2 Make and model of equipment.
17.3 Installation location.
17.4 Operational Status.
17.5 Date last tested.
17.6 Monitored Elements.
17.7 All identified channels.
17.8 Monitored electrical quantities.
C. Measures
M1. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
provided Sequence of Event recording capability in accordance with 1.1 and 1.2. (R1)
M2. Each Transmission Owner shall have, and provide upon request, evidence that it provided Fault
recording capability in accordance with 2.1 to 2.6. (R2)
M3. Each Transmission Owner shall have, and provide upon request, evidence that it provided Fault
recording capability that determined the Current Zero Time for loss of Bulk Electric System (BES)
transmission Elements in accordance with R3.
M4. Each Generator Owner shall have, and provide upon request, evidence that it provided Fault recording
capability for its Generating Plants at and above 200 MVA Capacity in accordance with R4.
M5. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
records for Faults, sufficient electrical quantities for each monitored Element to determine the
parameters listed in 5.1 to 5.5. (R5)
M6. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
provided Fault recording capability in accordance with 6.1 to 6.4. (R6)
M7. Each Reliability Coordinator shall have, and provide upon request, evidence that it established its
area’s requirements for Dynamic Disturbance Recording (DDR) capability in accordance with 7.1 and
.2. (R7)
M8. Each Reliability Coordinator shall have, and provide upon request, evidence that DDRs installed after
the approval of this standard function as continuous recorders. (R8)
M9. Each Reliability Coordinator shall have, and provide upon request, evidence that it developed DDR
setting triggers to include the parameters listed in 9.1 to 9.3. (R9)
M10. Each Reliability Coordinator shall have, and provide upon request, evidence that DDRs monitor the
Elements listed in 10.1 through 10.5. (R10)
M11. Each Reliability Coordinator shall have, and provide upon request, evidence that it documented
additional settings and deviations from the required trigger settings described in R9 and the required
list of monitored quantities as described in R10. (R11)
Adopted by NERC Board of Trustees: November 4, 2010
5
Standard PRC-002-NPCC-01— Disturbance Monitoring
M12. Each Reliability Coordinator shall have, and provide upon request, evidence that it specified its DDR
requirements which included the DDR setting triggers established in R9 to the Transmission Owners
and Generator Owners in the Reliability Coordinator’s area. (R12)
M13. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that
it acquired and installed the DDRs in accordance with the specifications contained in the Reliability
Coordinator’s request, and a mutually agreed upon implementation schedule. (R13)
M14. Each Transmission Owner and Generator Owner shall have, and provide upon request, evidence that it
has a maintenance and testing program for stand alone DME
(equipment whose only purpose is disturbance monitoring) that meets the requirements in 14.1
through 14.7. (R14)
M15. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it provided recorded disturbance data from DMEs within 30 days of the
receipt of the request from the entities listed in 15.1 and 15.2. (R15)
M16. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it submitted the data files in a format that meets the requirements in 16.1
through 16.3. (R16)
M17. Each Reliability Coordinator, Transmission Owner and Generator Owner shall have, and provide
upon request, evidence that it maintained a record of and provided to NPCC when requested, the data
on DMEs installed meeting the requirements 17.1 through 17.8. (R17)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
NPCC Compliance Committee
1.2. Compliance Monitoring Period and Reset Time Frame
Not Applicable
1.3. Data Retention
The Transmission Owner and Generator Owner shall keep evidences for three calendar years for
Measures 1, 5, 6, 13, 16 and 17.
The Transmission Owner shall keep evidence for three years for Measures 2 and 3.
The Generator Owner shall keep evidence for three years for Measure 4.
The Reliability Coordinator shall keep evidence for three years for Measures 7, 8, 9, 10, 11, 12,
16 and 17.
The Transmission Owner and Generator Owner shall keep evidences for twenty-four calendar
months for Measures 14 and 15.
The Reliability Coordinator shall keep evidence for twenty-four calendar months for Measure
15.
Adopted by NERC Board of Trustees: November 4, 2010
6
Standard PRC-002-NPCC-01— Disturbance Monitoring
If a Transmission Owner, Generator Owner or Reliability Coordinator is found non-compliant, it
shall keep information related to the non-compliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit and all subsequent record.
1.4. Compliance Monitoring and Assessment Processes
-
Self-Certifications
Spot Checking
Compliance Audits
Self-Reporting
Compliance Violation Investigations
Complaints
1.5. Additional Compliance Information
None
2.
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The Transmission
Owner or
Generator Owner
provided the
Sequence of
Event recording
capability
meeting the bulk
of R1 but
missed…
Up to and
including 10%
of the total set,
which is the
product of the
total number of
locations in 1.1
times the total
number of
parameters in
1.2.
More than 10% and
up to and including
20% of the total set,
which is the product
of the total number
of locations in 1.1
times the total
number of
parameters in 1.2.
More than 20% and
up to and including
30% of the total set,
which is the product
of the total number
of locations in 1.1
times the total
number of
parameters in 1.2.
More than 30% of the
total set, which is the
product of the total
number of locations in
1.1 times the total
number of parameters in
1.2.
R2
The Transmission
Owner provided
the Fault
recording
capability
meeting the bulk
of R2 but
missed…
Up to and
including 10%
of the total set,
which is the
total number of
Elements at all
locations
required to be
installed as per
R3 that meet
the criteria
listed in 2.1
through 2.6.
More than 10% and
up to and including
20% of the total set,
which is the total
number of Elements
at all locations
required to be
installed as per R3
that meet the criteria
listed in 2.1 through
2.6.
More than 20% and
up to and including
30% of the total set,
which is the total
number of
Elements at all
locations required
to be installed as
per R3 that meet
the criteria listed in
2.1 through 2.6.
More than 30% of the
total set, which is the
total number of Elements
at all locations required
to be installed as per R3
that meet the criteria
listed in 2.1 through 2.6.
Not applicable.
Not applicable.
Fault recording capability
that determines the
R3
Not applicable.
The Transmission
Adopted by NERC Board of Trustees: November 4, 2010
7
Standard PRC-002-NPCC-01— Disturbance Monitoring
Owner failed to
provide…
current zero time for loss
of transmission Elements.
Up to and
including 10%
of its
Generating
Plants at and
above 200
MVA Capacity
and connected
to a Bulk
Electric System
Element if
Fault recording
capability for
that portion of
the system is
inadequate.
R5
Up to and
The Transmission including 10%
Owner or
of the total set
Generator Owner of parameters,
failed to record
which is the
for the Faults… product of the
total number of
monitored
Elements and
the number of
parameters
listed in 5.1
through 5.5.
More than 10% and
up to and including
20% of its
Generating Plants at
and above 200 MVA
Capacity and
connected to a Bulk
Electric System
Element if Fault
recording capability
for that portion of
the system is
inadequate.
More than 20% and
up to 30% of its
Generating Plants at
and above 200 MVA
Capacity and
connected to a Bulk
Electric System
Element if Fault
recording capability
for that portion of
the system is
inadequate.
More than 30% of its
Generating Plants at and
above 200 MVA
Capacity and connected
to a Bulk Electric System
Element if Fault
recording capability for
that portion of the system
is inadequate.
More than 10% and
up to and including
20% of the total set
of parameters, which
is the product of the
total number of
monitored Elements
and the number of
parameters listed in
5.1 through 5.5.
More than 20% and
up to and including
30% of the total set
of parameters, which
is the product of the
total number of
monitored Elements
and the number of
parameters listed in
5.1 through 5.5.
More than 30% of the
total set of parameters,
which is the product of
the total number of
monitored Elements and
the number of parameters
listed in 5.1 through 5.5.
R6
The Transmission
Owner or
Generator Owner
failed …
To provide Fault
recording capability
for more than 10%
and up to and
including 20% of the
total set of
requirements, which
is the product of the
total number of
monitored Elements
and the total number
of capabilities
identified in 6.1
through 6.2.
OR
Failed to document
additional triggers or
To provide Fault
recording capability
for more than 20%
and up to and
including 30% of the
total set of
requirements, which
is the product of the
total number of
monitored Elements
and the total number
of 6.1 through 6.2.
OR
Failed to document
additional triggers or
deviations from the
settings stipulated in
To provide Fault
recording capability for
more than 30% of the
total set of requirements,
which is the product of
the total number of
monitored Elements and
the total number of
capabilities identified in
6.1 through 6.2.
OR
Failed to document
additional triggers or
deviations from the
settings stipulated in 6.3
through 6.4 for more than
ten (10) locations.
R4
The Generator
Owner failed to
provide Fault
recording
capability at…
To provide
Fault recording
capability for
up to and
including 10%
of the total set
of
requirements,
which is the
product of the
total number of
monitored
Elements and
the total
number of
capabilities
identified in 6.1
Adopted by NERC Board of Trustees: November 4, 2010
8
Standard PRC-002-NPCC-01— Disturbance Monitoring
deviations from the
through 6.2.
settings stipulated in
OR
6.3 through 6.4 for
Failed to
more than two (2)
document
and up to and
additional
including five (5)
triggers or
deviations from locations.
the settings
stipulated in 6.3
through 6.4 for
up to 2
locations.
More than 10% and
R7
Up to and
up to and including
The Reliability
including 10%
20% of the required
Coordinator
of the required
failed to establish DDR coverage DDR coverage for
its area as per 7.1
its area’s
for its area as
requirements
per 7.1and 7.2. and 7.2.
for…
R8
Not applicable. Not applicable.
The Reliability
Coordinator failed
to specify
that DDRs
installed…
R9
Not
The Reliability
applicable.
Coordinator failed
to specify that
DDRs are
installed
without…
R10
Not applicable.
The Reliability
Coordinator failed
to ensure that the
quantities listed in 10.1 through 10.5
are monitored or
derived…
Up to two (2)
R11
facilities within
The Reliability
Coordinator failed the Reliability
to document and Coordinator’s
area that have a
report to the
Regional Entity DDR.
upon request
additional settings and deviations
from the required
trigger settings
described in R9
6.3 through 6.4 for
more than five (5)
and up to and
including ten (10)
locations.
More than 20% and
up to and including
30% of the required
DDR coverage for
its area as per 7.1
and 7.2.
More than 30% of the
required DDR coverage
for its area as per 7.1 and
7.2.
Not applicable.
Function as continuous
recorders.
Not applicable.
Not applicable.
The capabilities listed in
9.1 through 9.3.
Not applicable.
Not applicable.
Where DDRs are
installed.
More than two (2)
and up to five (5)
facilities within the
Reliability
Coordinator’s area
that have a DDR.
More than five (5)
and up to ten (10)
facilities within the
Reliability
Coordinator’s area
that have a DDR.
More than ten (10)
facilities within the
Reliability Coordinator’s
area that have a DDR.
Adopted by NERC Board of Trustees: November 4, 2010
9
Standard PRC-002-NPCC-01— Disturbance Monitoring
and the required
list of monitored
quantities as
described in R10
for…
R12
Not applicable.
The Reliability
Coordinator failed
to specify to the
Transmission
Owners and
Generator Owners
its DDR
requirements
including the DDR setting
triggers
established in R9
but missed…
R13
Up to and
The Transmission including 10%
Owner or
of the
Generator Owner requirement set
failed to comply of the
with the
Reliability
Reliability
Coordinator’s
Coordinator’s
request to
request installing install DDRs,
the DDR in
with the
accordance with requirement set
R12 for…
being the total
number of
DDRs
requested times
the number of
setting triggers
specified for
each DDR.
R14
Established a
The Transmission maintenance
Owner or
and testing
Generator
program for
Owner…
stand alone
DME but
provided
incomplete data
for any one (1)
of 14.1 through
Not applicable.
Not applicable.
Established setting
triggers.
More than 10% and
up to 20% of the
requirement set
requested by the
Reliability
Coordinator for
installing DDRs,
with the requirement
set being the total
number of DDRs
requested times the
number of setting
triggers specified for
each DDR.
More than 20% and
up to 30% of the
requirement set
requested by the
Reliability
Coordinator for
installing DDRs,
with the requirement
set being the total
number of DDRs
requested times the
number of setting
triggers specified for
each DDR.
More than 30% of the
requirement set requested
by the Reliability
Coordinator and
installing DDRs, with the
requirement set being the
total number of DDRs
requested times the
number of setting triggers
specified for each DDR
OR
The Reliability
Coordinator,
Transmission Owners,
and Generator Owners
failed to mutually agree
on an implementation
schedule.
Established a
maintenance and
testing program for
stand alone DME
but provided
incomplete data for
more than one (1)
and up to and
including three (3)
of 14.1 through 14.7.
Established a
maintenance and
testing program for
stand alone DME
but provided
incomplete data for
more than three (3)
and up to and
including six (6) of
14.1 through 14.7.
Did not establish any
maintenance and testing
program for DME;
OR
The Transmission Owner
or Generator Owner
established a
maintenance and testing
program for DME but did
not provide any data that
Adopted by NERC Board of Trustees: November 4, 2010
10
Standard PRC-002-NPCC-01— Disturbance Monitoring
14.7.
R15
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
provided recorded
disturbance data
from DMEs but
was late for…
R16
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
failed to submit…
R17
The Reliability
Coordinator,
Transmission
Owner or
Generator Owner
failed to maintain
or provide to
the Regional
Entity , upon
request…
meets all of 14.1 through
14.7.
Up to and
including
fifteen (15)
days in meeting
the requests of
an entity, or
entities in 15.1,
or 15.2.
More than fifteen
(15) days but less
than and including
thirty (30) days in
meeting the requests
of an entity, or
entities in 15.1 or
15.2.
More than 30 days
but less than and
including forty-five
(45) days in meeting
the requests of an
entity, or entities in
15.1 or 15.2.
More than forty-five (45)
days in meeting the
requests of an entity, or
entities in 15.1 or 15.2.
Up to and
including two
(2) data files in
a format that
meets the
applicable
format
requirements in
16.1 through
16.3.
Up to and
including two
(2) of the items
in 17.1 through
17.8.
More than two (2)
and up to and
including five (5)
data files in a format
that meets the
applicable format
requirements in 16.1
through 16.3.
More than five (5)
and up to and
including ten (10)
data files in a format
that meets the
applicable format
requirements in 16.1
through 16.3.
More than ten (10) data
files in a format that
meets the applicable
format requirements in
16.1 through 16.3.
More than two (2)
and up to and
including four (4) of
the items in 17.1 to
17.8.
More than four (4)
and up to and
including six (6) of
the items in 17.1
through 17.8.
More than six (6) of the
items in 17.1 through
17.8.
E. Associated Documents
Version History
Version
Date
Action
Change Tracking
1
November 4,
2010
Adopted by NERC Board of Trustees
New
1
October 20,
2011
FERC Order issued approving PRC002-NPCC-01 (FERC’s Order became
effective on October 20, 2011)
Adopted by NERC Board of Trustees: November 4, 2010
11
March 31, 2016
To: NERC Board of Trustees
Subject: Request for Approval, Retirement of NPCC Regional Reliability Standard PRC-002NPCC-01 Disturbance Monitoring.
On March 23, 2016 in accordance with the NPCC Regional Standard Processes Manual the
NPCC Board of Directors approved the retirement of NPCC Regional Standard PRC-002NPCC-01 Disturbance Monitoring.
The subject standard was originally adopted by the NERC Board of Trustees on November 4,
2010 and approved by the FERC on October 20, 2011. The standard was subject to enforcement
on October 20, 2013. FERC recently approved the NERC continent-wide standard PRC-002-2
Disturbance Monitoring and Reporting Requirements, which becomes enforceable on July 1,
2016. NPCC participated in the development of the continent-wide standard and attributes of the
Regional standard were incorporated into PRC-002-2.
Upon approval of the continent-wide standard by the FERC, NPCC’s Task Force on System
Protection, acting as a standard review/drafting team, initiated an analysis to determine if there
was a reliability related need to maintain the Regional standard. The results of the review, as
attached, indicated that the continent-wide standard’s requirements were sufficient and redundant
in their objectives with the Regional standard and identified where any differences are addressed
by NPCC’s existing more stringent reliability criteria.
Further, in accordance with the NERC “Regional Reliability Standards Evaluation Procedure
2.1”, the proposal to retire the standard has been posted by NERC and no non-supportive
comments were received.
Accordingly, NPCC is requesting that PRC-002-NPCC-01 be retired effective the later of July 1,
2016 or the date the retirement is approved by the applicable regulatory authorities. Contingent
upon the approval of the NERC BOT, NPCC will work with NERC Legal Staff in order to
prepare the necessary filings and petitions.
Thank you for your consideration.
Ruida Shu
Northeast Power Coordinating Council, Inc.
Senior Engineer, Reliability Standards and Criteria
Main: 212-840-1070
Direct: 917-934-7976
Fax: 212-302-2782
Email: [email protected]
PRC-002-NPCC-01 REQUIREMENTS
LOCATIONS FOR DATA CAPTURE (SER, FR)
R1. Each Transmission Owner and Generator Owner
shall provide Sequence of Event (SER) recording
capability by installing Sequence of Event
recorders or as part of another device, such as a
Supervisory Control And Data Acquisition (SCADA)
Remote Terminal Unit (RTU), a generator plant
Digital (or Distributed) Control System (DCS) or
part of Fault recording equipment. This capability
shall:
1.1 Be provided at all substations and at
locations where circuit breaker operation
affects continuity of service to radial Loads
greater than 300MW, or the operation of
which drops 50MVA Nameplate Rating or
greater of Generation, or the operation of
which creates a Generation/Load island.
Be provided at generating units above
50MVA Nameplate Rating or series of
generating units utilizing a control scheme
such that the loss of 1 unit results in a loss
of greater than 50MVA Nameplate
Capacity, and at Generating Plants above
300MVA Name Plate Capacity.
1.2 Monitor the following at each location
listed in 1.1:
1.2.1 Transmission and Generator circuit
breaker positions
1.2.2 Protective Relay tripping for all
Protection Groups that operate to trip
circuit breakers identified in 1.2.1.
1.2.3 Teleprotection keying and receive
R2. Each Transmission Owner shall provide Fault
recording capability for the following Elements at
facilities where Fault recording equipment is
required to be installed as per R3:
2.1 All transmission lines.
2.2 Autotransformers or phase-shifters connected
to busses.
2.3 Shunt capacitors, shunt reactors.
2.4 Individual generator line interconnections.
2.5 Dynamic VAR Devices.
2.6 HVDC terminals.
R7. Each Reliability Coordinator shall establish its
area’s requirements for Dynamic Disturbance
PRC-002-2 REQUIREMENTS
LOCATIONS FOR DATA CAPTURE (SER,
FR)
R1. Each Transmission Owner shall:
1.1. Identify BES buses for which sequence
of events recording (SER) and fault
recording (FR) data is required by using
the methodology in PRC-002-2,
Attachment 1.
1.2. Notify other owners of BES Elements
connected to those BES buses, if any,
within 90-calendar days of completion of
Part 1.1, that those BES Elements
require SER data and/or FR data.
1.3. Re-evaluate all BES buses at least once
every five calendar years in accordance
with Part 1.1 and notify other owners, if
any, in accordance with Part 1.2, and
implement the re-evaluated list of BES
buses as per the Implementation Plan.
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
LOCATIONS FOR DATA CAPTURE (SER, FR)
3.2. Sequence of Event recorders shall be provided at
all bulk power system substations and at
generating units above 50 MW capacity, and at
generating plants above 300 MW capacity
4.3 Fault recording capability shall be provided by the
GO for generating units above 200 MW capacity.
4.4 Fault recorders shall monitor the following
elements at each location where fault recorders
are installed:
- All BPS Transmission Lines
- Autotransformers or phase-shifters connected to
BPS busses
- Shunt capacitors 345 kV and above
- Individual generator interconnections
- Dynamic Var Devices
- HVDC Terminals
- A Transmission Owner may optionally include the
monitoring of transformers
serving load from a BPS bus.
5.2 On an Area basis, there shall be at least ten (10)
DDRs per 30,000 MW of peak load, distributed
throughout the system, and installed at various
types of locations, with consideration given to the
following factors:
- Major load centers
- Major generation clusters
- Major voltage sensitive areas
- Major transmission interfaces
- Major transmission junctions
- Elements associated with Interconnection
Reliability Operating Limits (IROLs)
- Major EHV interconnections between control
areas.
5.3 An evaluation of the need for a DDR should be
made upon each new major BPS installation and
upon each bulk power system station addition or
expansion where a fault recorder replacement
project is being made. (A field for this purpose will
be included in the next revision of
Document C-22.)
5.4 DDRs shall monitor the following elements at each
location where dynamic recorders are installed:
- Most lines such that normal maintenance
1
Because of its Attachment 1 Methodology for
Selecting Buses for Capturing Sequence of
Events Recording (SER) and Fault Recording (FR)
Data in PRC-002-2, PRC-002-2 does not require
SER coverage at as many buses as PRC-002NPCC-01. There is no FR or SER required by
PRC-002-2 from generators.
Locations requiring monitoring in PRC-002NPCC-01 were amended by Compliance
Guidance Statements CGS-002 Defining
Generator Materiality for Registration dated
May 4, 2009 (to be retired 7/1/16), CGS-004
Generating Plant Capacity in PRC-002-NPCC-01
dated March 20, 2013, and CGS-005 Clarification
of Monitoring and Enforcement of PRC-002NPCC-01.
A-15 Revisions Needed
Specifics provided in the sections below on SOE
(PRC-002-NPCC-01), SER (PRC-002-2), Fault
recording (FR), and DDR.
PRC-002-NPCC-01 REQUIREMENTS
Recording (DDR) capability that:
7.1 Provides a minimum of 1 DDR per 3,000 MW
of peak Load.
7.2 Records dynamic disturbance information
with consideration of the following
facilities/locations:
7.2.1 Major Load centers.
7.2.2 Major Generation clusters.
7.2.3 Major voltage sensitive areas.
7.2.4 Major transmission interfaces.
7.2.5 Major transmission junctions.
7.2.6 Elements associated with
Interconnection Reliability Operating
Limits (IROLs).
7.2.7 Major EHV interconnections between
operating areas.
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
activities do not interfere with DDR requirements.
- Bus voltages
2
A-15 Revisions Needed
PRC-002-NPCC-01 REQUIREMENTS
SOE
PRC-002-2 REQUIREMENTS
SER
R1. Each Transmission Owner and Generator Owner
shall provide Sequence of Event (SER) recording
capability by installing Sequence of Event
recorders or as part of another device, such as a
Supervisory Control And Data Acquisition (SCADA)
Remote Terminal Unit (RTU), a generator plant
Digital (or Distributed) Control System (DCS) or
part of Fault recording equipment. This capability
shall:
1.1 Be provided at all substations and at
locations where circuit breaker operation
affects continuity of service to radial Loads
greater than 300MW, or the operation of
which drops 50MVA Nameplate Rating or
greater of Generation, or the operation of
which creates a Generation/Load island.
R2. Each Transmission Owner and Generator
Owner shall have SER data for circuit breaker
position (open/close) for each circuit breaker
it owns connected directly to the BES buses
identified in Requirement R1 and associated
with the BES Elements at those BES buses.
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
SOE
3.2. Sequence of Event recorders shall be provided at
all bulk power system substations and at
generating units above 50 MW capacity, and at
generating plants above 300 MW capacity
3.3. Sequence of Events recording shall monitor the
following at each location:
- Transmission and Generator circuit breaker
positions
- Protective Relay tripping for all protection
groups
- Teleprotection keying & receive
Be provided at generating units above
50MVA Nameplate Rating or series of
generating units utilizing a control scheme
such that the loss of 1 unit results in a loss
of greater than 50MVA Nameplate
Capacity, and at Generating Plants above
300MVA Name Plate Capacity.
1.2 Monitor the following at each location
listed in 1.1:
1.2.1 Transmission and Generator circuit
breaker positions
1.2.2 Protective Relay tripping for all
Protection Groups that operate to
trip circuit breakers identified in
1.2.1.
1.2.3 Teleprotection keying and receive
3
PRC-002-NPCC-01 is more specific and inclusive
in the locations (substations and generating
units) where SOE is to be provided (PRC-002NPCC-01 Parts 1.1 and 1.2). Also more specific
in that it specifies that SER is to be provided for
protective relay tripping and teleprotection
keying.
A-15 Revisions Needed
3.2--for generating units, 50MW to be changed
to 50MVA, 300MW to 300MVA.
Add radial loads greater than 300MW, or the
operation of which creates a Generation/Load
island.
Bulk power system to be changed to Bulk
Electric System.
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
FAULT RECORDING
FAULT RECORDING
FAULT RECORDING
R2. Each Transmission Owner shall provide Fault
recording capability for the following Elements at
facilities where Fault recording equipment is
required to be installed as per R3:
2.1 All transmission lines.
2.2 Autotransformers or phase-shifters connected
to busses.
2.3 Shunt capacitors, shunt reactors.
2.4 Individual generator line interconnections.
2.5 Dynamic VAR Devices.
2.6 HVDC terminals.
R3. Each Transmission Owner and Generator
Owner shall have FR data to determine the
following electrical quantities for each
triggered FR for the BES Elements it owns
connected to the BES buses identified in
Requirement R1:
3.1 Phase-to-neutral voltage for each
phase of each specified BES bus.
3.2 Each phase current and the residual or
neutral current for the following BES
Elements:
3.2.1 Transformers that have a low-side
operating voltage of 100kV or above.
3.2.2 Transmission Lines.
4.1 Fault recording is the responsibility of
transmission owners and generation owners.
When adding or replacing a DFR at an existing BPS
facility, the TO or GO should complete a
notification in accordance with Document C-22.
R3. Each Transmission Owner shall have Fault
recording
capability that determines the Current Zero Time
for
loss of Bulk Electric System (BES) transmission
Elements.
R4. Each Generator Owner shall provide Fault
recording
capability for Generating Plants at and above
200 MVA Capacity and connected through a
generator step up (GSU) transformer to a Bulk
Electric System Element unless Fault recording
capability is already provided by the Transmission
Owner.
R5. Each Transmission Owner and Generator Owner
shall record for Faults, sufficient electrical
quantities
for each monitored Element to determine the
following:
5.1 Three phase-to-neutral voltages. (Common
busside voltages may be used for lines.)
5.2 Three phase currents and neutral currents.
5.3 Polarizing currents and voltages, if used.
5.4 Frequency.
5.5 Real and reactive power.
R6. Each Transmission Owner and Generator Owner
shall provide Fault recording with the following
capabilities:
6.1 Each Fault recorder record duration shall be a
minimum of one (1) second.
6.2 Each Fault recorder shall have a minimum
recording rate of 16 samples per cycle
R4. Each Transmission Owner and Generator
Owner shall have FR data as specified in
Requirement R3 that meets the following:
4.1 A single record or multiple records
that include:
• A pre-trigger record length of at least
two cycles and a total record length of
at least 30-cycles for the same trigger
point, or
• At least two cycles of the pre-trigger
data, the first three cycles of the posttrigger data, and the final cycle of the
fault as seen by the fault recorder.
4.2 A minimum recording rate of 16
samples per cycle.
4.3 Trigger settings for at least the
following:
4.3.1 Neutral (residual) overcurrent.
4.3.2 Phase undervoltage or
overcurrent.
4.2 Fault recording shall be provided by the TO to
determine the current zero time for loss of BPS
transmission elements. The current zero time shall
be reported as the time of the final current zero
on the last phase to interrupt.
4.3 Fault recording capability shall be provided by the
GO for generating units above 200 MW capacity.
4.4 Fault recorders shall monitor the following
elements at each location where fault recorders
are installed:
- All BPS Transmission Lines
- Autotransformers or phase-shifters connected to
BPS busses
- Shunt capacitors 345 kV and above
- Individual generator interconnections
- Dynamic Var Devices
- HVDC Terminals
- A Transmission Owner may optionally include the
monitoring of transformers
serving load from a BPS bus.
4.5 Electrical quantities to be recorded for each
monitored element shall be sufficient to
determine the following:
- Three phase-to-neutral voltages. (Common busside voltages may be used for lines.)
- Three phase currents and neutral currents.
- Polarizing currents and voltages, if used.
- Frequency.
- Active and reactive power.
4.6 Fault recorder record duration shall be a minimum
of one (1) second.
4.7 Fault recorder minimum recording rate shall be 16
samples per cycle.
4.8 As a minimum, fault recorders shall be set to
trigger for all the following
functions:
4
Because of its Attachment 1 Methodology for
Selecting Buses for Capturing Sequence of
Events Recording (SER) and Fault Recording (FR)
Data, PRC-002-2 doesn’t require SER coverage at
as many buses as PRC-002-NPCC-01.
Current Zero Time is not addressed in PRC-0022.
There NO FR required by PRC-002-2 from
generators.
PRC-002-2 does not require recording polarizing
currents or voltages, frequency, and real and
reactive power.
PRC-002-NPCC-01 specifies a record duration of
one (1) second. PRC-002-2 specifies “at least
30-cycles” or “two cycles of the pre-trigger
data…and the final cycle of the fault…”
PRC-002-NPCC-01 specifies fault recorder
triggering for specified per unit values of rated
CT secondary current, set per unit values of
neutral (residual) overcurrent, specified
undervoltage per unit value, and documentation
of additional triggers when necessary.
A-15 Revisions Needed
Triggering for monitored phase overcurrent set
at 1.5 pu or less.
4.4--Change BPS to BES
Remove “345kV and above” from shunt
capacitors
Add shunt reactors
4.1--Change BPS to BES
4.2-- Change BPS to BES
4.3--Change MW to MVA
4.5--Change Active to Real
4.8--Add monitored phase overcurrent set at
1.5 pu or less of rated CT secondary
current
Add “or greater” to “Phase undervoltage
set at 0.85 pu”
PRC-002-NPCC-01 REQUIREMENTS
6.3 Each Fault recorder shall be set to trigger for
at least the following:
6.3.1 Monitored phase overcurrents set at 1.5 pu
or less of rated CT secondary current or
Protective Relay tripping for all Protection
Groups.
6.3.2 Neutral (residual) overcurrent set at 0.2 pu
or less of rated CT secondary current.
6.3.3 Monitored phase undervoltage set at 0.85
pu or greater.
6.4 Document additional triggers and deviations
from the settings in 6.3.2 and 6.3.3 when local
conditions dictate.
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
- Protective Relay tripping for all protection
groups
- Neutral (residual) overcurrent set at 0.2 pu rated
CT secondary current
- Phase undervoltage set at 0.85 pu
4.9 When local conditions require different settings
or additional functions, such situations shall be
documented.
5
A-15 Revisions Needed
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
DYNAMIC DISTURBANCE RECORDING
DYNAMIC DISTURBANCE RECORDING
DYNAMIC DISTURBANCE RECORDING
R7. Each Reliability Coordinator shall establish its
area’s requirements for Dynamic Disturbance
Recording (DDR) capability that:
7.1 Provides a minimum of 1 DDR per 3,000 MW
of peak Load.
7.2 Records dynamic disturbance information
with consideration of the following
facilities/locations:
7.2.1 Major Load centers.
7.2.2 Major Generation clusters.
7.2.3 Major voltage sensitive areas.
7.2.4 Major transmission interfaces.
7.2.5 Major transmission junctions.
7.2.6 Elements associated with
Interconnection Reliability Operating
Limits (IROLs).
7.2.7 Major EHV interconnections between
operating areas.
R5. Each Responsible Entity shall:
5.1 Identify BES Elements for which dynamic
Disturbance recording (DDR) data is
required, including the following:
5.1.1 Generating resource(s) with:
5.1.1.1 Gross individual nameplate
rating greater than or equal
to
500 MVA.
5.1.1.2 Gross individual
nameplate rating greater
than or equal to 300 MVA
where the
gross plant/facility aggregate
nameplate rating is greater
than or equal to 1,000 MVA.
5.1.2 Any one BES Element that is part of a
stability (angular or voltage) related
System Operating Limit (SOL).
5.1.3 Each terminal of a high voltage
direct current (HVDC) circuit
with a nameplate rating greater
than or equal to 300 MVA, on
the alternating current (AC)
portion of the converter.
5.1.4 One or more BES Elements that
are part of an Interconnection
Reliability Operating Limit
(IROL).
5.1.5 Any one BES Element within a
major voltage sensitive area as
defined by an area with an inservice undervoltage load
shedding (UVLS) program.
5.2 Identify a minimum DDR coverage,
inclusive of those BES Elements identified
in Part 5.1, of at least:
5.2.1 One BES Element; and
5.2.2 One BES Element per 3,000
MW of the Responsible Entity’s
historical simultaneous peak
System Demand.
5.3 Notify all owners of identified BES
Elements, within 90-calendar
days of
completion of Part 5.1, that their
respective BES Elements require DDR data
when requested.
5.4 Re-evaluate all BES Elements at least once
5.1 Where the DDR capability is deemed necessary by
the Reliability Coordinator, the Reliability
Coordinator shall provide guidance in setting
triggers and shall monitor the performance of the
DDR devices.
R8. Each Reliability Coordinator shall specify that
DDRs installed, after the approval of this
standard,
function as continuous recorders.
R9. Each Reliability Coordinator shall specify that
DDRs are installed with the following
capabilities:
9.1 A minimum recording time of sixty (60)
seconds per trigger event.
9.2 A minimum data sample rate of 960 samples
per second, and a minimum data storage rate
for
RMS quantities of six (6) data points per
second.
9.3 Each DDR shall be set to trigger for at least
one of the following (based on manufacturers’
equipment capabilities):
9.3.1 Rate of change of Frequency.
9.3.2 Rate of change of Power.
9.3.3 Delta Frequency (recommend 20 mHz
change).
9.3.4 Oscillation of Frequency.
R10. Each Reliability Coordinator shall establish
requirements such that the following quantities
are monitored or derived where DDRs are
installed:
10.1 Line currents for most lines such that
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
5.2 On an Area basis, there shall be at least ten (10)
DDRs per 30,000 MW of peak load, distributed
throughout the system, and installed at various
types of locations, with consideration given to the
following factors:
- Major load centers
- Major generation clusters
- Major voltage sensitive areas
- Major transmission interfaces
- Major transmission junctions
- Elements associated with Interconnection
Reliability Operating Limits (IROLs)
- Major EHV interconnections between control
areas.
5.3 An evaluation of the need for a DDR should be
made upon each new major BPS installation and
upon each bulk power system station addition or
expansion where a fault recorder replacement
project is being made. (A field for this purpose will
be included in the next revision of
Document C-22.)
5.4 DDRs shall monitor the following elements at each
location where dynamic recorders are installed:
- Most lines such that normal maintenance
activities do not interfere with DDR requirements.
- Bus voltages
5.5 As a minimum, DDRs shall monitor one phase
current per monitored element and two phase-toneutral voltages of different elements. One of the
monitored voltages shall be of the same phase as
the monitored current.
5.6 Electrical quantities to be recorded for each
monitored element shall be sufficient to
determine the following:
- Voltage, current, and frequency
- Active and reactive power
5.7 DDRs installed after January 1, 2009 shall function
6
For non-continuous recorders, PRC-002-2
specifies triggered record lengths of at least 3
minutes versus 60 seconds for PRC-002-NPCC01 (R9).
PRC-002-2 specifies an output recording rate
of at least 30 times per second. PRC-002NPCC-01 specifies a minimum data storage
rate of 6 data points per second.
PRC-002-2 specifies an off nominal frequency
trigger (if used).
PRC-002-2 is specific on the rate of change of
frequency trigger values (if used).
PRC-002-2 specifies an undervoltage trigger (if
used).
PRC-002-NPCC-01 specifies a rate of change of
Power trigger (if used).
PRC-002-NPCC-01 specifies a Delta Frequency
trigger (if used), and an oscillation of
Frequency trigger (if used).
PRC-002-2 stipulates that normal line
maintenance does not interfere with DDR
functionality for monitoring line currents.
PRC-002-2 stipulates that normal bus
maintenance does not interfere with DDR
functionality for monitoring bus voltages.
PRC-002-NPCC-01 addresses DDR installation.
PRC-002-2 does not address equipment.
A-15 Revisions Needed
5.1--Add “The Reliability Coordinator shall
request DDR capability, and shall, with
Transmission Owners, and Generator
Owners mutually agree on an
implementation schedule.”
5.2--Change “control” to “operating”.
5.3--Change BPS to BES
Change “bulk power System” to Bulk
Electric System
5.4--Revise first bullet to read “Lines and
buses such that …”
5.4--“Bus voltages” should be “bus”.
5.6--Change Active to real.
Add 5.12:
Each Reliability Coordinator shall
document additional settings and
deviations from the required trigger
settings and the required list of monitored
quantities and report this to NPCC upon
request.
PRC-002-NPCC-01 REQUIREMENTS
normal line maintenance activities do not
interfere with DDR functionality.
10.2 Bus voltages such that normal bus
maintenance activities do not interfere
with DDR functionality.
10.3 As a minimum, one phase current per
monitored Element and two phase-toneutral voltages of different Elements. One
of the monitored voltages shall be of the
same phase as the monitored current.
10.4 Frequency.
10.5 Real and reactive power.
R11. Each Reliability Coordinator shall document
additional settings and deviations from the
required trigger settings described in R9 and the
required list of monitored quantities as
described in R10, and report this to the Regional
Entity (RE) upon request.
R12. Each Reliability Coordinator shall specify its DDR
requirements including the DDR setting triggers
established in R9 to the Transmission Owners
and Generator Owners.
R13. Each Transmission Owner and Generator Owner
that receives a request from the Reliability
Coordinator to install a DDR shall acquire and
install the DDR in accordance with R12.
Reliability Coordinators, Transmission Owners,
and Generator Owners shall mutually agree on
an implementation schedule.
PRC-002-2 REQUIREMENTS
every five calendar years in accordance
with Parts 5.1 and 5.2, and notify owners
in accordance with Part 5.3 to implement
the re-evaluated list of BES Elements as
per the Implementation Plan.
R6. Each Transmission Owner shall have DDR data
to determine the following electrical
quantities for each BES Element it owns for
which it received notification as identified in
Requirement R5: [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning ]
6.1 One phase-to-neutral or positive sequence
voltage.
6.2 The phase current for the same phase at
the same voltage corresponding to the
voltage in Requirement R6, Part 6.1, or the
positive sequence current.
6.3 Real Power and Reactive Power flows
expressed on a three phase basis
corresponding to all circuits where current
measurements are required. 6.4
Frequency of any one of the voltage(s) in
Requirement R6, Part 6.1.
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
as continuous recorders.
5.8 Each device shall sample data at a rate of at least
960 samples per second (16 samples per cycle and
shall store the RMS value of electrical quantities at
a rate of at least 6 data points per second.)
5.9 The following DDR triggers shall be considered
where available based on manufacturers
capability:
- Rate of change of Frequency
- Rate of change of Power
- Delta Frequency 20 mHz change
- Oscillation of Frequency
5.10 When local conditions require different settings
or additional functions, such situations shall be
documented.
5.11 When DDR triggers are used, duration of
triggered records shall be a minimum of
sixty (60) seconds.
R7. Each Generator Owner shall have DDR data to
determine the following electrical quantities for
each BES Element it owns for which it received
notification as identified in Requirement R5:
7.1 One phase-to-neutral, phase-to-phase, or
positive sequence voltage at either the
generator step-up transformer (GSU) highside or low-side voltage level.
7.2 The phase current for the same phase at
the same voltage corresponding to the
voltage in Requirement R7, Part 7.1, phase
current(s) for any phase-to-phase voltages,
or positive sequence current.
7.3 Real Power and Reactive Power flows
expressed on a three phase basis
corresponding to all circuits where current
measurements are required.
7.4 Frequency of at least one of the voltages
in Requirement R7, Part 7.1.
R8. Each Transmission Owner and Generator
Owner responsible for DDR data for the BES
Elements identified in Requirement R5 shall have
continuous data recording and storage. If the
equipment was installed prior to the effective
7
A-15 Revisions Needed
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
date of this standard and is not capable of
continuous recording, triggered records must
meet the following:
8.1 Triggered record lengths of at least three
minutes.
8.2 At least one of the following three
triggers:
• Off nominal frequency trigger set at:
Low
High
o Eastern Interconnection <59.75Hz
>61.0Hz
o Western Interconnection <59.55Hz
>61.0Hz
o ERCOT Interconnection <59.35Hz >61.0
Hz
o Hydro-Quebec
Interconnection
<58.55Hz
>61.5Hz
• Rate of change of frequency trigger set at:
o Eastern Interconnection
< -0.03125 Hz/sec >0.125
Hz/sec o Western Interconnection
< -0.05625 Hz/sec >0.125
Hz/sec o ERCOT Interconnection
< -0.08125 Hz/sec >0.125
Hz/sec o Hydro-Quebec Interconnection
< -0.18125 Hz/sec >0.1875
Hz/sec • Undervoltage trigger set no lower than
85
percent of normal operating voltage for a
duration of 5 seconds.
R9. Each Transmission Owner and Generator
Owner responsible for DDR data for the BES
Elements identified in Requirement R5 shall
have DDR data that meet the following:
9.1 Input sampling rate of at least 960
samples per second.
9.2 Output recording rate of electrical
quantities of at least 30 times per second.
8
A-15 Revisions Needed
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
TIME SYNCHRONIZATION
TIME SYNCHRONIZATION
TIME SYNCHRONIZATION
R14. Each Transmission Owner and Generator Owner
shall establish a maintenance and testing
program for stand alone DME (equipment
whose only purpose is disturbance monitoring)
that includes:
14.1 Maintenance and testing intervals and their
basis.
14.2 Summary of maintenance and testing
procedures.
14.3 Monthly verification of communication
channels used for accessing records
remotely (if the entity relies on remote
access and the channel is not monitored to
a control center staffed around the clock,
24 hours a day, 7 days a week (24/7)).
14.4 Monthly verification of time
synchronization (if the loss of time
synchronization is not
monitored to a 24/7 control center).
14.5 Monthly verification of active analog
quantities.
14.6 Verification of DDR and DFR settings in the
software every six (6) years.
14.7 A requirement to return failed units to
service within 90 days. If a DME device will
be out of
service for greater than 90 days the owner
shall keep a record of efforts aimed at
restoring the DME to service.
R10. Each Transmission Owner and Generator
Owner shall time synchronize all SER and FR
data for the BES buses identified in
Requirement R1 and DDR data for the BES
Elements identified in Requirement R5 to
meet the following:
10.1 Synchronization to Coordinated Universal
Time (UTC) with or without a local time
offset.
10.2 Synchronized device clock accuracy
within ± 2 milliseconds of UTC.
7.0 Time Synchronization
Internal clocks in DME devices shall be time
synchronized to within 2 milliseconds or less of
Coordinated Universal Time (UTC) scale. The time
zone shall be clearly identified as either universal
time zone or local time zone.
PRC-018-1 Requirement
R1. Each Transmission Owner and Generator
Owner required to install DMEs by its
Regional Reliability Organization (reliability
standard PRC-002 Requirements 1-3) shall
have DMEs installed that meet the following
requirements:
R1.1. Internal Clocks in DME devices shall be
synchronized to within 2 milliseconds or
less of Universal Coordinated Time
scale (UTC)
R1.2. Recorded data from each Disturbance
shall be retrievable for ten calendar
days.
9
PRC-002-2, and PRC-018-1 (to be retired 6 years
after the implementation date for PRC-002-2)
specify synchronization of ± 2 milliseconds and
its coordination to UTC.
A-15 Revisions Needed
Section 6--Add 7.1:
Monthly verification of time synchronization
(if the loss of time synchronization is not
monitored to a 24/7 control center).
NOTE: This is also in B-26 Guide for
Application of Disturbance Recording
Equipment
PRC-002-NPCC-01 REQUIREMENTS
DATA SPECIFICATIONS
R15. Each Reliability Coordinator, Transmission
Owner and Generator Owner shall share data
within 30 days upon request. Each Reliability
Coordinator, Transmission Owner, and
Generator Owner shall provide recorded
disturbance data from DMEs within 30 days of
receipt of the request in each of the following
cases:
15.1 NERC, Regional Entity, Reliability
Coordinator.
15.2 Request from other Transmission Owners,
Generator Owners within NPCC.
R16. Each Reliability Coordinator, Transmission
Owner and Generator Owner shall submit the
data files conforming to the following format
requirements:
16.1 The data files shall be capable of being
viewed, read, and analyzed with a generic
COMTRADE analysis tool as per the latest
revision of IEEE Standard C37.111.
16.2 Disturbance Data files shall be named in
conformance with the latest revision of
IEEE Standard C37.232.
16.3 Fault Recorder and DDR Files shall contain
all monitored channels. SER records shall
contain station name, date, time resolved to
milliseconds, SER point name, status.
PRC-002-2 REQUIREMENTS
DATA SPECIFICATIONS
R11. Each Transmission Owner and Generator
Owner shall provide, upon request, all SER
and FR data for the BES buses identified in
Requirement R1 and DDR data for the BES
Elements identified in Requirement R5 to the
Responsible Entity, Regional Entity, or
NERC in accordance with the following:
11.1 Data will be retrievable for the period of
10-calendar days, inclusive of the day the
data was recorded.
11.2 Data subject to Part 11.1 will be provided
within 30-calendar days of a request
unless an extension is granted by the
requestor.
11.3 SER data will be provided in ASCII
Comma Separated Value (CSV) format
following Attachment 2.
11.4 FR and DDR data will be provided in
electronic files that are formatted in
conformance with C37.111, (IEEE
Standard for Common Format for
Transient Data Exchange (COMTRADE),
revision C37.111-1999 or later.
11.5 Data files will be named in conformance
with C37.232, IEEE Standard for
Common Format for Naming Time
Sequence Data Files (COMNAME),
revision C37.232-2011 or later.
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
DATA SPECIFICATIONS
PRC-002-2 stipulates 30 days unless an
extension is granted.
6.1 Recorded disturbance data from DMEs shall be
forwarded within 30 days of receipt of the request
in each of the following cases:
- Request from NERC Disturbance Investigation
Team
- Request from NPCC Disturbance Investigation
Team
- Reliability Coordinator Request
PRC-002-2 is more specific on the data
parameters.
6.2 Data forwarded shall be archived in its native
format for a period of 3 years by the TO or GO.
PRC-002-NPCC-01 is more specific as to the time
resolution for SER data.
6.3 Disturbance data files shall be provided in a
format which is capable of being viewed, read,
and analyzed with a generic COMTRADE analysis
tool (8).
PRC-018-1 stipulates archiving of data for at
least three years. A-15 specifies archiving for 3
years. Note: PRC-018-1 is going to be retired in
six years after the implementation period for
PRC-002-2.
6.4 Disturbance Data files shall be named in
conformance with IEEE C37.232 Recommended
Practice for Naming Time Sequence Data Files.
6.5 Fault Recorder and DDR Files shall contain all
monitored channels. SER records shall contain
station, date, time resolved to milliseconds, SER
point name, status.
6.6 Recorded data from each disturbance shall be
retrievable for 10 calendar days. This requirement
does not apply to relays unless those relays are
designated as DME.
______________________________________________
PRC-018-1 Requirement
R1. Each Transmission Owner and Generator
Owner required to install DMEs by its
Regional Reliability Organization (reliability
standard PRC-002 Requirements 1-3) shall
have DMEs installed that meet the following
requirements:
R1.1. Internal Clocks in DME devices shall be
synchronized to within 2 milliseconds or
less of Universal Coordinated Time
scale (UTC)
R1.2. Recorded data from each Disturbance
shall be retrievable for ten calendar
10
PRC-002-2 and PRC-018-1 stipulate that data is
retrievable for 10 calendar days.
A-15 Revisions Needed
Section 6-NOTE: This is also in C-25 Procedure to
Collect Power System Event Data for
Analysis of System Performance
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
days.
R4. The Transmission Owner and Generator
Owner shall each provide Disturbance data
(recorded by DMEs) in accordance with its
Regional Reliability Organization’s
requirements (reliability standard PRC-002
Requirement 4).
R5. The Transmission Owner and Generator
Owner shall each archive all data recorded
by DMEs for Regional Reliability
Organization-identified events for at least
three years.
11
A-15 Revisions Needed
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
STATUS OF RECORDING CAPABILITY
STATUS OF RECORDING CAPABILITY
STATUS OF RECORDING CAPABILITY
R14. Each Transmission Owner and Generator Owner
shall establish a maintenance and testing
program for stand alone DME (equipment
whose only purpose is disturbance monitoring)
that includes:
14.1 Maintenance and testing intervals and their
Basis.
14.2 Summary of maintenance and testing
procedures.
14.3 Monthly verification of communication
channels used for accessing records
remotely (if the entity relies on remote
access and the channel is not monitored to
a control center staffed around the clock,
24 hours a day, 7 days a week (24/7)).
14.4 Monthly verification of time
synchronization (if the loss of time
synchronization is not
monitored to a 24/7 control center).
14.5 Monthly verification of active analog
quantities.
14.6 Verification of DDR and DFR settings in the
software every six (6) years.
14.7 A requirement to return failed units to
service within 90 days. If a DME device will
be out of
service for greater than 90 days the owner
shall keep a record of efforts aimed at
restoring the DME to service.
R12. Each Transmission Owner and Generator
Owner shall, within 90-calendar days of the
discovery of a failure of the recording
capability for the SER, FR or DDR data,
either:
• Restore the recording capability, or
• Submit a Corrective Action Plan (CAP)
Regional Entity and implement it.
8.0 Maintenance And Testing
Each TO, and GO shall establish a maintenance and
testing program for DME (guidance for
maintenance and testing is provided in Document
B-26) that includes:
• Maintenance and testing intervals and their
basis.
• Summary of maintenance and testing
procedures.
_____________________________________________
PRC-018-1 Requirement
R6. Each Transmission Owner and Generator
Owner that is required by its Regional
Reliability Organization to have DMEs shall
have a maintenance and testing program for
those DMEs that includes:
R6.1. Maintenance and testing intervals and
their basis.
R6.2. Summary of maintenance and testing
procedures.
12
A-15 Revisions Needed
With the exception of PRC-002-NPCC-01 Part
14.4 (time synchronization), Requirement R14
to be added.
NOTE: This is also in B-26 Guide for
Application of Disturbance Recording
Equipment
PRC-002-NPCC-01 REQUIREMENTS
PRC-002-2 REQUIREMENTS
A-15
Differences Between PRC-002NPCC-01 and PRC-002-2
DATA ON THE DISTURBANCE MONITORING
EQUIPMENT
DATA ON THE DISTURBANCE
MONITORING EQUIPMENT
DATA ON THE DISTURBANCE MONITORING
EQUIPMENT
R17. Each Reliability Coordinator, Transmission
Owner and Generator Owner shall maintain, record
and
provide to the Regional Entity (RE), upon request, the
following data on the DMEs installed to meet
this standard:
17.1 Type of DME.
17.2 Make and model of equipment.
17.3 Installation location.
17.4 Operational Status.
17.5 Date last tested.
17.6 Monitored Elements.
17.7 All identified channels.
17.8 Monitored electrical quantities.
Not Applicable.
6.7 The TO and GO shall each maintain and be ready
to report to NPCC on request the following data
on the DMEs installed to meet this standard:
- Type of DME
- Make and model of equipment
- Installation location
- Operational Status
- Date last tested
- Monitored Elements
- Monitored Devices
- Monitored Electrical Quantities
_____________________________________________
PRC-018-1 Requirement
R3. The Transmission Owner and Generator
Owner shall each maintain, and report to its
Regional Reliability Organization on request,
the following data on the DMEs installed to
meet that region’s installation requirements
(reliability standard PRC-002
Requirements1.1, 2.1 and 3.1):
R3.1. Type of DME (sequence of event
recorder, fault recorder, or dynamic
disturbance recorder).
R3.2. Make and model of equipment.
R3.3. Installation location.
R3.4. Operational status.
R3.5. Date last tested.
R3.6. Monitored elements, such as
transmission circuit, bus section, etc.
R3.7. Monitored devices, such as circuit
breaker, disconnect status, alarms, etc.
R3.8. Monitored electrical quantities, such as
voltage, current, etc.
13
No gaps with PRC-018-1.
A-15 Revisions Needed
6.7--Revise “Monitored Devices” bullet to read
“All identified channels”
PRC-002-NPCC-02 Disturbance Monitoring Draft Team Roster
Name:
Company:
Qualifications:
Don Burkart
Con Edison
Robert
Grabovickic
National Grid
Tim Kucey
PSEG
Brian EvansMongeon
Utility
Services
Robert Pellegrini
Jim Watson
UI
Dynergy
George Wegh
Eversource
Paul Difilippo
Hydro One
Ruida Shu
NPCC
Don has 5 years in relay protection engineering and have had countless
experiences in system event analyses. Additionally, He is the Lead Disciple
Engineer for the company wide DME programs.
Responsibilities include the analysis of events and system disturbances,
protection co-ordination studies, calculations of settings for protection relays
and disturbance fault recorders (DFRs), configuration of DFRs for NY PMU
project, reviewing the relay settings of generators owned by customers, the
development of protection standards.
Member of current NPCC PRC-002-NPCC review SDT (joined SDT in
2013 in response to membership solicitation).
Co-lead of the “Tools and Training” team of the NERC investigation of the
August 2003 Northeast Blackout. Responsible for the bulk of the team’s
findings/discoveries – and the associated write-ups in the NERC and USCanada Bilateral Commission reports - regarding key entities’
implementation, usage and the performance of system monitoring and
analysis “tools” (e.g. EMS, RTCAs, SEs) involved in the incident.
For the period 1994 through to 2002, technical positions with process and
power industry DCS/EMS, SCADA and RTU OEMs: Fisher-Rosemount
(now Emerson); Moore Process Control (now Siemens); GE Harris
(previously Westronics, HDAP; now GE Power).
NERC Manager of Enforcement and Mitigation from 2006 until 2010, then
NERC’s CEA agent (Manager of NOP Development) until late 2011. Duties
included review of all compliance actions taken by NERC to the NERC
BOT Compliance Committee, frequent engagement with the CCC and the
Standards Committee, FERC staff, SDTs. Also involvement in several
NERC events analyses/investigations and joint NERC-FERC 1B actions,
typically involving transmission organizations, balancing authorities and
reliability coordinators.
As a prior member of the drafting team, he believe that he is qualified to
serve again. He has been involved in numerous drafting teams including
EOP-004, PRC-006 for both NPCC and NERC, BES, and Dispersed
Generating Resources. He also serve on the NPCC RCC and the NERC PC,
ERSTF, and RBRTF.
Involved in designing P&C SCADA systems
He has been employed in the electric utility industry for 33 years in the areas
of generation operations, planning, and environmental compliance and for
the last 4 years – NERC compliance.
George has over 25 years of Electrical Engineering experience, of which 15
years have been in the utility industry. He is presently the Manager of
Transmission Protection and Controls Engineering at Eversource Energy.
He has been working in the Transmission Protection and Controls
Department at Eversource Energy for over 8 years. He presently serve as
the NPCC representative on the NERC System Protection and Controls
Subcommittee (SPCS) and am Vice Chairman of the NPCC Task Force on
System Protection (TFSP).
28 years of experience in various aspects of protection systems at Hydro
One including analysis of the 2003 Northeast blackout utilizing all available
DME in Ontario.
Member of TFSP since 2008 and current Chair.
He is also the requester for the RSAR.
NPCC Standards Staff. Ruida Shu has 8+ years of experience in
Lee Pedowicz
NPCC
Daniel Kidney
NPCC
Distribution, Transmission, SCADA, Construction, Daily Electric
Operations, Facility Maintenance, Security, DOE/FEMA/APPA Grant
Projects, Safety, Compliance and Reliability Standards.
Manager of Reliability Standards at NPCC. Chair of PRC-002-2 Drafting
Team. System operations real-time operating and outage scheduling,
protective system testing, and substation design experience.
NPCC Compliance Staff. Daniel has been a member of the Compliance
Enforcement staff at NPCC since 2014. Prior to joining NPCC, he was
employed as a Transmission Planner at Central Maine Power.
November 16, 2015
Subject: Notification of (10) Day Ballot Period for Retirement of Regional Standard PRC-002-NPCC-01
Disturbance Monitoring
Dear Madam/Sir:
On October 8, 2015, in accordance with the NPCC Regional Standards Process Manual (RSPM), the
NPCC Regional Standards Committee (RSC) acting on the recommendation of the PRC-002-NPCC-01
Drafting Team, initiated the process to retire NPCC Regional Standard PRC-002-NPCC-01 Disturbance
Monitoring.
The PRC-002-NPCC-01 standard drafting team was convened to address an RSC approved Regional
Standard Authorization Request (RSAR) which proposed retiring PRC-002-NPCC-01 subsequent to FERC
approval of PRC-002-2 Disturbance Monitoring and Reporting Requirements. PRC-002-2 was approved
by the FERC on September 25, 2015 without any directives issued.
In accordance with the RSPM the retirement of PRC-002-NPCC-01 must be initially approved by the
NPCC Full and General Members, with subsequent approvals by the NPCC Board of Directors, NERC
Board of Trustees and finally filing with the applicable governmental authorities.
The PRC-002-NPCC-01 standard and all supporting documentation have been posted on the NPCC
Website for a ten (10) day ballot period beginning November 16th, 2016.
https://www.npcc.org/Standards/SitePages/DevStandardDetail.aspx?DevDocumentId=120
Please contact me with any questions.
Thank you.
Ruida Shu
Northeast Power Coordinating Council, Inc.
Senior Engineer, Reliability Standards and Criteria
Main: 212-840-1070
Direct: 917-934-7976
Fax: 212-302-2782
Email: [email protected]
December 2nd, 2015
NPCC Full and General Members:
In accordance with the NPCC Regional Standard Processes Manual the ballot period for the
retirement of NPCC Regional Standard PRC-002-NPCC-01 Disturbance Monitoring closed at
23:59PM on November 26th, 2015.
The results of the ballot were as follows:
Quorum: 69% of the Total Registered
Approval: 97.10%
No negative ballots were received with comments therefore, in accordance with our Standards
Processes Manual a recommendation for final Regional approval will be sent to the NPCC Board
of Directors for consideration at their meeting on February 2, 2016.
Contingent upon the approval of the NPCC BOD, the proposal to retire PRC-002-NPCC-01 will
be submitted to the NERC Board of Trustees with subsequent filings with the FERC and
applicable provincial authorities.
Voting was conducted electronically and the full retirement record for the standard may be
viewed at:
https://www.npcc.org/Standards/SitePages/DevStandardDetail.aspx?DevDocumentId=120
Thank you for your participation.
Ruida Shu
Northeast Power Coordinating Council, Inc.
Senior Engineer, Reliability Standards and Criteria
Main: 212-840-1070
Direct: 917-934-7976
Fax: 212-302-2782
Email: [email protected]
1. Determine Quorum
NPCC Registered Members
Sector 1, Transmission Owners
19
Central Hudson Gas and Electric Corporation
1
Central Maine Power Company
1
Consolidated Edison Company of New York, Inc.
1
Emera Maine
1
Eversource
1
Hydro One Inc
1
Hydro-Quebec TransEnergie
1
Long Island Power Authority
1
National Grid
1
New Brunswick Power Transmission Corporation 1
New Hampshire Transmission, LLC
1
New York Power Authority
1
New York State Electric & Gas
1
Nova Scotia Power Inc.
1
NStar Electric Company
1
Orange and Rockland Utilities Inc
1
Rochester Gas & Electric
1
The United Illuminating Company
1
Vermont Transco
1
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
15
0
1
1
1
1
1
1
1
1
1
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
14
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1. Determine Quorum
NPCC Registered Members
Sector 2, Reliability Coordinators
Hydro-Quebec TransEnergie
Independent Electricity System Operator
ISO-New England, Inc.
New Brunswick System Operator
New York Independent System Operator
5
1
1
1
1
1
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
5
0
1
1
1
1
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
5
0
0
1
1
1
1
1
1. Determine Quorum
NPCC Registered Members
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
Sector 3, TDUs, Dist. And LSE
20
13
0
Braintree Electric Light Department
1
1
Consolidated Edison Company of New York, Inc. 1
1
Eversource
1
Groton Electric Light
1
1
Hingham Municipal Lighting Plant
1
1
Hydro One Inc
1
1
Hydro Quebec Distribution
1
1
Ipswich Municipal Light Department
1
Long Island Power Authority
1
1
Marblehead Municipal Light Department
1
National Grid
1
1
New York Power Authority
1
Orange and Rockland Utilities Inc
1
1
Princeton Municipal Light Department
1
1
Shrewsbury Electric & Cable Operations
1
1
Sterling Municipal Light Department
1
Toronto Hydro Electric System Ltd.
1
Vermont Electric Cooperative, Inc.
1
Wakefield Municipal Gas and Light Department
1
1
Westfield Gas & Electric Light Department
1
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
12
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1. Determine Quorum
NPCC Registered Members
Sector 4, Generator Owners
22
Consolidated Edison Company of New York, Inc.
1
Covanta Energy
1
Dominion Resources Inc.
1
Dynegy, Inc.
1
Entergy Nuclear Northeast
1
Eversouce
1
Exelon Generation
1
First Wind Operations & Maintenance
1
International Power America
1
Long Island Power Authority
1
Massachusetts Municipal Wholesale Electric Company 1
New York Power Authority
1
NextEra Energy Resources
1
NRG Energy Inc.
1
Nova Scotia Power Inc.
1
Ontario Power Generation Inc.
1
PSEG Power Connecticut, LLC
1
PSEG Power New York, LLC
1
Talen Energy Marketing, LLC
1
TransCanada
1
US Power Generating Company, LLC
1
Wheelabrator Westchester LP
1
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
17
0
1
1
1
1
1
1
1
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
17
0
0
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
1. Determine Quorum
NPCC Registered Members
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
Sector 5, Marketers, Brokers, Aggragators
14
8
0
Brookfield Power Corporation
1
1
Consolidated Edison Company of New York, Inc.
1
1
Consolidated Edison Energy/Development
1
Constellation New Energy, Inc.
1
HQ Energy Marketing Inc.
1
1
H.Q. Energy Services (U.S.) Inc.
1
1
Long Island Power Authority
1
Massachusetts Municipal Wholesale Electric Company 1
1
Nalcor Energy
1
New York Power Authority
1
1
PSEG Energy Resources & Trade, LLC
1
1
Shell Energy North America
1
Utility Services Inc.
1
1
Windy Bay Power, LLC
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
8
0
0
1
1
1
1
1
1
1
1
1. Determine Quorum
NPCC Registered Members
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
Sector 6, State and Provincial Reg. and Govt. Authorities
7
4
0
Long Island Power Authority
1
1
Maine Public Utilities Commission
1
1
Massachusetts Attorney General
1
1
New Hampshire Public Utilities Commission
1
New York Power Authority
1
1
New York State Department of Public Service 1
Vermont Department of Public Service
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
4
0
0
1
1
1
1
1. Determine Quorum
NPCC Registered Members
In Attendance By Proxy
(denote w/ 1) (denote w/ 1)
Sector 7, Sub Regional Rel. Councils, REs and 13
Others
7
0
4g Technologies, LP
1
Ascendant Energy Solutions, Inc.
1
Energy Sector Security Consortium, Inc.
1
ERLPhase Power Technologies
1
1
International Business Machines Corporation 1
McCoy Power Consultants, Inc.
1
1
New York State Reliability Council, LLC
1
1
Oxbow-Sherman Energy, LLC
1
1
PLM, Inc.
1
1
Preti, Flaherty, Beliveau, and Pachios, LLP.
1
Proven Compliance Solutions, Inc.
1
1
SGC Engineering, LLC
1
1
VIASYN, Inc.
1
2. Vote/Ballot Recording
Affirmative
Negative
Abstain
(denote w/ 1) (denote w/ 1) (denote w/ 1)
7
0
0
1
1
1
1
1
1
1
Determine Electronic Quorum
Sector
1
2
3
4
5
6
7
Sector Name
Transmission Owners
Reliability Coordinators
TDUs, Dist. And LSE
Generator Owners
Marketers, Brokers, Aggragators
Customers- large and small
State and Provincial Reg. and Govt. Authorities
Total
In
Registered Attendance
19
15
5
5
20
13
22
17
14
8
7
4
13
7
100
69
Electronic Vote Quorum= at least 2/3 of the Total Registered
Quorum Present?
YES
By
Proxy
Total
Represented
0
15
0
5
0
13
0
17
0
8
0
4
0
7
0
69
Sector %
Attending
0.79
1.00
0.65
0.77
0.57
0.57
0.54
Determine if Motion or Item Passes
Sector
Affirmative
Negative
Abstain Votes Cast
has
# of
# of
# of
Total
Voted(1Registered Attending Votes Fraction Votes Fraction Votes (-Abstentions) Y, 0-N)
Sector
Sector Name
1
2
3
4
5
6
7
Transmission Owners
Reliability Coordinators
TDUs, Dist. And LSE
Generator Owners
Marketers, Brokers, Aggragators
Customers- large and small
State and Provincial Reg. and Govt. Authorities
19
5
20
22
14
7
13
Totals
100
Sum of Affirmative/Number of Sectors that Voted
MUST BE AT LEAST 2/3 to pass
Did MOTION PASS?
Total
Sector %
0.79
1.00
0.65
0.77
0.57
0.57
0.54
14
5
12
17
8
4
7
67
1.000
PASS
1.000
1.000
1.000
1.000
1.000
1.000
1.000
7.000
0
0
0
0
0
0
0
0
0.000
0.000
0.000
0.000
0.000
0.000
0.000
0.000
1
0
1
0
0
0
0
14
5
12
17
8
4
7
1
1
1
1
1
1
1
2
67
7
REGIONAL STANDARDS COMMITTEE
Chairman:
Guy V. Zito
Assistant Vice President - Standards
Northeast Power Coordinating Council, Inc.
Tel. (212) 840-1070
Email: [email protected]
Co-Vice Chairman:
Si Truc Phan
Engineer – Reliability Standards & Operating Procedures
Reliability Coordinator
2 Complexe Desjardins, 19th floor, East Tower
Montreal, Québec, Canada H5B 1H7
Tel. (514) 879-4100 Ext. 3610
Email: [email protected]
Co-Vice Chairman:
Bruce Metruck
Director, Reliability Standards & Compliance
New York Power Authority
F.R. Clark Energy Center
6520 Glass Factory Road
Marcy, NY 13403
Tel. (315) 792-8213
Email: [email protected]
Sector 1 - Transmission Owners
Hydro One Networks, Inc.
Primary
Paul Malozewski, P. Eng., MBA, PMP
Manager – Reliability Standards and Strategies
Tel. 416-345-5005
Email: [email protected]
Alternate
Payam Farahbakhsh, M. Eng, P. Eng.
Network Management Engineer – Reliability
Standards and Strategies
Tel. (416) 345-5484
Email: [email protected]
Consolidated Edison Company of New York, Inc.
Primary
Michael Forte
Chief Transmission Planning Engineer
Tel. (212) 460-3416
Fax (212) 529-1130
Email: [email protected]
Alternate
Martin Paszek
Manager, Bulk Power System Performance and
Analysis
Tel. (212) 460-6415
Fax (212) 529-1130
Email: [email protected]
National Grid
Primary
Brian Shanahan
Lead Engineer
Transmission Control Center – NY
National Grid, US
Tel. (315) 460-4346
Email: [email protected]
Alternate
Michael Schiavone
Director, Transmission Control Center – NY
National Grid, US
Tel. (315) 460-4472
Email: [email protected]
New Brunswick Power Corporation
Primary
Rob Vance, P.Eng.
Power System Engineer
Tel. (506) 458-3922
Email: [email protected]
Alternate
The United Illuminating Company
Primary
Alternate
Michele Tondalo
Compliance Analyst
180 Marsh Hill Road
Orange, Connecticut 06477
Tel. (203) 499-2542
Email: [email protected]
Hydro-Quebec TransÉnergie
Primary
Sylvain Clermont
Manager Transmission Services
Tel. (514) 879-4648
Email: [email protected]
Alternate
Orange & Rockland Utilities, Inc.
Primary
Edward Bedder
Compliance Program Manager
Tel. (845) 577-3827
Fax (845) 577-3256
Email: [email protected]
Alternate
Boris Shulim
Section Manager – Substation & Transmission
Engineering
Orange and Rockland Utilities Inc.
390 West Route 59
Spring Valley NY 10977
845-577-3716
Email: [email protected]
Eversource Energy
Primary
Mark J. Kenny
Program Manager - Reliability Compliance
Eversource Energy
Westwood, MA 02090
Tel. (781) 441-8179
Cell. (617) 429-1837
Email: [email protected]
Alternate
Quintin Lee
Program Manager - Reliability Compliance
Eversource Energy
780 North Commercial Street
Manchester, NH 03101
Office: (603) 634-3579
Cell: (603) 634-3562
Email: [email protected]
Sector (2) - Reliability Coordinators
New York Independent System Operator
Primary
Gregory A. Campoli
Manager, Reliability Compliance & Industry
Affairs
Tel. (518) 356-6159
Email: [email protected]
Alternate
James (Jim) Grant
Reliability Senior Engineer
Tel. (518) 356-6128
Email: [email protected]
ISO New England, Inc.
Primary
Kathleen M. Goodman
Senior Operations Compliance Coordinator
Tel. (413) 535-4111
Email: [email protected]
Alternate
Matthew Goldberg
Director of Reliability & Operations Compliance
Tel. (413) 535-4029
Email: [email protected]
Independent Electricity System Operator
Primary
Helen Lainis
Senior Engineer/Technical Officer
Tel. (905) 855-4106
Email: [email protected]
Alternate
Scott Berry
Senior Engineer/Technical Officer
Tel. (905) 403-6912
Email: [email protected]
Hydro-Quebec TransÉnergie
Primary
Si Truc Phan
Engineer – Reliability Standards & Operating
Procedures
Reliability Coordinator
2 Complexe Desjardins, 19th floor, East Tower
Montreal, Québec, Canada H5B 1H7
Tel. (514) 879-4100 Ext. 3610
Email: [email protected]
Alternate
Chantal Mazza
Direction Contrôle des Mouvements d'énergie
C.P. 10000, succ. pl Desjardins
Complexe Desjardins 19th floor
Montréal, QC H5B 1H7
Tel. (514) 879-4100 Ext. 5499
Email: [email protected]
New Brunswick Power Corporation
Primary
Randy MacDonald
Director, Corporate Compliance
Tel. (506) 458-4653
Cell. (506) 470-3536
Email: [email protected]
Alternate
Sector (3) - Transmission Dependent Utilities (“TDUs”); Distribution Companies and Load-Serving
Entities (“LSEs”)
Consolidated Edison Company of New York, Inc.
Primary
Kelly Silver
Engineer – Standards and Compliance
Room 1300 NW 4 Irving Place NY, NY 10003
Tel. (212) 460-4155
Fax (845) 577-3256
Email: [email protected]
Alternate
Dermot Smyth
Senior Enigneer
Tel. (212) 460-4093
Fax (212) 529-1130
Email: [email protected]
National Grid
Primary
Michael Jones
Lead Analyst – FERC Compliance
40 Sylvan Road
Waltham, Massachusetts 02451
Tel. (781) 907-2404
Email: [email protected]
Alternate
Orange & Rockland Utilities, Inc.
Primary
David Burke
Senior Specialist - Compliance
Tel. (845) 577-2841
Fax (845) 577-2840
Email: [email protected]
Alternate
Ben Wu
Principal Engineer
Transmission & Substation Engineering
Tel. (845) 577-3713
Email: [email protected]
Sector (4) - Generator Owners
Consolidated Edison Company of New York, Inc.
Primary
Peter Yost
Manager, Standards & Compliance
Tel. (212) 460-2889
Fax (212) 529-1130
Email: [email protected]
Alternate
Robert Winston
Sr. Engineer
Tel. (212) 460-2790
Fax (212) 529-1130
Email: [email protected]
New York Power Authority
Primary
Wayne Sipperly
NERC Compliance Program Manager II
Tel. (914) 287-3753
Email: [email protected]
Alternate
Salvatore Spagnolo
Senior Reliability Standards & Compliance
Engineer I
Tel. (914) 390-8224
Mob. (347) 992-7015
Email: [email protected]
Dominion Resources Services, Inc.
Primary
Connie Lowe
NERC Compliance Policy Manager
Dominion Resources Services, Inc.
Tel. (804) 819-2917
Email: [email protected]
Alternate
Lou Oberski
Managing Director NERC Compliance Policy
Dominion Resources Services, Inc.
Tel. (804) 819-2837
Email: [email protected]
Ontario Power Generation, Inc.
Primary
David Ramkalawan, P.Eng.
Senior Manager - Reliability Compliance
Tel. (416) 592-6089
Email: [email protected]
Alternate
NextEra Energy, LLC
Primary
Silvia Parada Mitchell
Director, Reliability Standards & Compliance
Tel. (561) 904-3767
Email: [email protected]
Alternate
Summer Esquerre
Manager, Reliability Standards & Compliance
Tel. (561) 904-3765
Email: [email protected]
Alternate
Rogelio Moraitis
Compliance Analyst
Reliability Standards and Compliance
Tel. (561) 904-3402
Email: [email protected]
Entergy Services, Inc
Primary
Glen Smith
NERC Compliance
Entergy Services, Inc
440 Hamilton Avenue
White Plains, NY 10601
914-272-3513
Email: [email protected]
Alternate
Sector (5) - Marketers, Brokers and Aggregators
Consolidated Edison Company of New York, Inc.
Primary
Brian O’Boyle
Engineer
Tel. (212) 460-5596
Fax (212) 529-1130
Email: [email protected]
Alternate
Alyson Slanover
Engineer
Tel. (212) 460-8351
Fax (212) 529-1130
Email: [email protected]
Utility Services, Inc.
Primary
Brian Robinson
Compliance Analyst
Tel. (802) 241-1400
Email: [email protected]
Alternate
Brian Evans-Mongeon
President/CEO
Tel. (802) 241-1400
Email: [email protected]
Sector (6) – State and Provincial Regulatory and/or Governmental Authorities
New York Power Authority
Primary
Bruce Metruck
NERC Compliance Program Manager II
F.R. Clark Energy Center
6520 Glass Factory Road
Marcy, NY 13403
Tel. (315) 792-8213
Email: [email protected]
Alternate
Shivaz Chopra
RSC Engineer II, Technical Compliance
Tel. (914) 681-6828
Email: [email protected]
New York State Department of Public Service
Primary
Vijay Puran
Utility Engineer 3
Tel. (518) 486-5948
Email: [email protected]
Alternate
Jerry Ancona
Senior Engineer
Tel. (315) 428-5160
Email: [email protected]
Sector 7 – Sub-Regional Reliability Councils, Customers and Other Regional Entities and
Interested Entities
New York State Reliability Council, LLC
Primary
Alan Adamson
Independent Consultant
2104 Braxton Street
Clermont, FL 34711
Tel. (352) 989-4653
Email: [email protected]
Alternate
| File Type | application/pdf |
| File Modified | 2016-04-04 |
| File Created | 2016-03-31 |