PRC-002-NPCC-01: Disturbance Monitoring
Purpose
Ensure that adequate disturbance datais 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.
Applicability
(Proposed) Effective Date
To be established
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 than50MVA 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: [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 capabilityis 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 cycle
6.3 Each Fault recorder shall be set totrigger for at least the following:
6.3.1 Monitored phase overcurrents set at 1.5 pu orless 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.
R7. 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]
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 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 DDRshall 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 isdisturbance 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 latestrevision 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.
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.
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 provideupon request, evidence that it provided Fault recording capability in accordance with 2.1 to 2.6. (R2)
M3. Each Transmission Owner shall have, and provideupon 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 settingsdescribed in R9 and the required list of monitored quantities as described in R10. (R11)
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 inaccordance with the specificationscontained 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 fromDMEs 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)