1. PMUs for NERC Reliability Standards Ryan D. Quint, Ph.D., P.E. Staff Coordinator, NERC SMS, SAMS WECC JSIS Meeting September 22, 2015

2. RELIABILITY | ACCOUNTABILITY2 DISCLAIMER: This is not Compliance Guidance material; the goal is to illustrate application of synchrophasor technology as it relates to NERC Reliability Standards. Pre-Screening: This material will be incorporated into:  NASPI Starter Kit – Simplified version of this presentation  NASPI Tutorial – Detailed discussion of this presentation  SMS “PMUs for NERC Reliability Standards” – Comprehensive look at wider range on NERC Reliability Standards and application of PMUs DISCLAIMER

3. RELIABILITY | ACCOUNTABILITY3 Starter Kit Highlights This list highlights the more mature, high-value applications  Comprehensive list will be developed by NERC SMS Standard Number TitleStatus BAL-003-1Frequency Response and Frequency Bias SettingSubject to Enforcement FAC-001-2Facility Interconnection RequirementsSubject to Enforcement IRO-003-2Reliability Coordination – Wide-Area ViewSubject to Enforcement MOD-026-1Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Subject to Enforcement MOD-027-1Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Subject to Enforcement MOD-033-1Steady-State and Dynamic System Model ValidationSubject to Enforcement PRC-002-2Disturbance Monitoring and Reporting RequirementsSubject to Future Enforcement

4. RELIABILITY | ACCOUNTABILITY4 Requires “sufficient Frequency Response from the Balancing Authority (BA) to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the frequency is restored to its scheduled value.” Provides “consistent methods for measuring Frequency Response and determining Frequency Bias Setting” BAL-003-1: Frequency Response and Frequency Bias Setting

5. RELIABILITY | ACCOUNTABILITY5 Frequency Response Analysis Tool (FRAT)

6. RELIABILITY | ACCOUNTABILITY6 FAC-001-2 “avoid[s] adverse impacts on the reliability of the Bulk Electric System.” Transmission Owners and applicable Generator Owners must document and make Facility Interconnection requirements available so that entities seeking to interconnection will have the necessary information.” Standards does not explicitly specify any requirements for synchrophasor technology; However, many utilities have realized the value in this capability, and are requiring PMU monitoring at new generation interconnections  Facility Connections Requirements (FCR)  Open Access Transmission Tariff (OATT) FAC-001-2: Facility Interconnection Requirements

7. RELIABILITY | ACCOUNTABILITY7 EntityReference PJMhttp://www.pjm.com/documents/agreements.aspx http://www.pjm.com/documents/manuals.aspx BPAhttp://www.bpa.gov/transmission/Doing%20Business/Interconnection/Pages/default. aspx AESOhttp://www.aeso.ca/rulesprocedures/18592.html ERCOThttp://www.ercot.com/mktrules/guides/noperating Duke Midwesthttp://www.ferc.duke-energy.com/DEW/MidwestConnection.pdf IPChttps://www.idahopower.com/pdfs/BusinessToBusiness/facilityRequirements.pdf FCR and OATT References Handful of utilities have incorporated PMU installation into their Facility Connection Requirements (FCR) documents as per FAC- 001 or in their Open Access Transmission Tariff (OATT).

8. RELIABILITY | ACCOUNTABILITY8 PJM Interconnection (PJM) Revision to OATT  new generators >= 100 MW  “…entering the…Queue on or after October 1, 2012…”  “…with a proposed new Customer Facility that has a Maximum Facility Output equal to or greater than 100 MW…”  “…shall install and maintain, at its expense, phasor measurement units (PMUs).”  “PMUs shall be installed on the Customer Facility low side of the generator step-up transformer, unless it is a non-synchronous generation facility, in which case the PMUs shall be installed on the Customer Facility side of the Point of Interconnection.”  “…must be capable of… a minimum of 30 samples per second…”  “…which are synchronized via a high-accuracy satellite clock.”  “…similar quality equipment, such as relays or digital fault recorders, that can collect data…and which data is synchronized via a high-accuracy satellite clock…would satisfy this requirement.”

9. RELIABILITY | ACCOUNTABILITY9 PJM Interconnection (PJM) Modifications to OATT  “…PMU equipment which includes the communication circuit capable of carrying the PMU data to a local data concentrator, and then transporting the information continuously to the Transmission Provider…as well as store the PMU data locally for thirty days.”  “Interconnection Customer shall provide to [TP] all necessary and requested information through the [TP] synchrophasor system, including…:” o (a) gross MW and MVAR measured at the Customer Facility side of the generator step-up transformer (or, for a non-synchronous generation facility, to be measured at the Customer Facility side of the Point of Interconnection); o (b) generator terminal voltage; o (c) generator terminal frequency; and o (d) generator field voltage and current, where available.  “…Transmission Provider will install and provide for…ongoing support and maintenance of the network communications linking the data concentrator to the Transmission Provider.”

10. RELIABILITY | ACCOUNTABILITY10 PJM Interconnection (PJM) Addition to PJM Manual 14D: Generator Operational Requirements, Section 4.3  Section 4.3.1: Phasor Measurement Device Unit Requirements  Section 4.3.2: Phasor Data Concentrator (PDC) Requirements  Section 4.3.3: Network Requirements  Section 4.3.4: Data Exchange and Management Requirements

11. RELIABILITY | ACCOUNTABILITY11 Bonneville Power Administration (BPA) Modification to Technical Requirements for Interconnection to the BPA Transmission Grid  “…by measuring bus voltage and frequency, and generation current and power.”  “Performance monitoring is required to fully validate performance and verify the model provided under Section 5.3.8.”  “BPA will collect disturbance data and…perform performance validation. If BPA observes…discrepancy between…data and monitored results, the [GO] shall be required to perform…testing of the generation equipment.”  “…requires PMU…at all generation projects…directly connected to the BPA grid at voltages 230-kV and above, and at some lower voltage interconnections when identified during the interconnection studies.”  “The PMU will be installed at the project substation (typically a collector station if a wind generation project) and will measure quantities at either the low side or high side of each substation step-up transformer (e.g. 34.5/230 kV).”

12. RELIABILITY | ACCOUNTABILITY12 Bonneville Power Administration (BPA) Modification to Technical Requirements for Interconnection to the BPA Transmission Grid  “BPA will install the PMU and the required communication circuits/equipment at the project substation to transport the information to the Control Center.”  “…BPA may also require a continuous data stream to a BPA Phasor Data Concentrator (PDC) located at the BPA Point of Interconnection via the installed communications network at the project substation.”  “…PMU must be tested after configuration (but prior to installation) for compliance with IEEE C37.118 standard and WECC filtering and dynamic performance requirements.”

13. RELIABILITY | ACCOUNTABILITY13 Alberta Electric System Operator (AESO) Modification to ISO Rules, Section 502.9: Synchrophasor Measurement Unit Technical Requirements  “…A legal owner of a generating unit, legal owner of an aggregated generating facility or legal owner of a transmission facility who is a legal owner of a generating unit… for which the ISO issues a functional specification…  “…on or after the effective date of this section 502.9 [2/28/2013], must design and construct its facility in accordance with the minimum synchrophasor measurement unit requirements…and verify to the ISO that the facility meets the requirements during commissioning and energization of the new facility.” o Synchrophasor Measurement Unit Functionality o Synchrophasor Measurement Unit Signal Names o Data Storage and Streaming o Suspected Failure or Malfunction of a Synchrophasor Measurement Unit o As-Built Drawings

14. RELIABILITY | ACCOUNTABILITY14 Electric Reliability Council of Texas (ERCOT) Modification to Nodal Operating Guides (NOG)  Revised December 17, 2014  (1)“The Facility owner(s), whether a TSP or new Generation Entity, shall install phasor measurement recording equipment at the following Facilities. The installation shall occur not later than 18 months after a written notification from ERCOT to the Facility owner. o (a) Flexible AC transmission system devices configured to actively control steady-state voltage or power transfer capability, operated at or above 100kV, and energized after July 1, 2015; o (b) One Transmission Facility identified by ERCOT associated with each published generic transmission constraint as deemed necessary by ERCOT; and o (c) New generating Facilities over 20 MVA aggregated at a single site placed into service after January 1, 2017;”

15. RELIABILITY | ACCOUNTABILITY15 Requires that each “Reliability Coordinator must have a wide- area view of its own Reliability Coordinator Area and that of neighboring Reliability Coordinators.” Requirement R1 focuses on monitoring “all [BES] facilities… within its Reliability Coordinator Area and adjacent Reliability Coordinator Areas, as necessary to ensure that, at any time, regardless of prior planned or unplanned events, the Reliability Coordinator is able to determine any potential System Operating Limit and Interconnection Reliability Operating Limit violations within its Reliability Coordinator Area.” IRO-003-2: Reliability Coordination – Wide-Area View

16. RELIABILITY | ACCOUNTABILITY16 MOD-026: Generator excitation control system or plant volt/var control functions MOD-027: Turbine/governor and load control or active power/frequency control functions Applicability:  Individual generating unit greater than 100 MVA gross nameplate rating  Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 100 MVA gross aggregate nameplate rating Process:  R1. TP provides instructions and model data to GO  R2. GO provides verified model back to TP  R3. TP can provide oversight of model and performance  R4. GO provides revised model/plans upon any changes made MOD-026-1 & MOD-027-1: Verification of Models and Data

17. RELIABILITY | ACCOUNTABILITY17 Requirement R3: “…receiving one of the following items for an applicable unit:”  “Written comments and supporting evidence from its Transmission Planner indicating that the simulated excitation control system or plant volt/var control function model response did not match the recorded response to a transmission system event.” Requirement R5: “Each [GO] shall provide a written response to its Transmission Planner…following receipt of a technically justified* unit request from the [TP] to perform a model review of a unit or plant…”  “Corrected model data including the source of revised model data…”  *technical justified: achieved by the [TP] demonstrating that the simulated unit or plant response does not match the measured unit or plant response. MOD-026-1 & MOD-027-1: Verification of Models and Data

18. RELIABILITY | ACCOUNTABILITY18 Located at the Point(s) of Interconnection (POI) Measurements required  Playback: o Bus voltage magnitude and phase angle o Bus frequency  Measures of success: o Plant (or unit) MWs and MVARs PMUs for Model Verification Source: BPA

19. RELIABILITY | ACCOUNTABILITY19 GO provides “verified” model to the TP Prior to PMU-based verification, TP used model at face value With PMU-based verification, TP can VALIDATE the verified model Value of Event Verification Source: BPA

20. RELIABILITY | ACCOUNTABILITY20 Establishes “validation requirements to facilitate the collection of accurate data and building of planning models to analyze the reliability of the interconnected transmission system.” Requirement R1 requires the Planning Coordinator (PC) to implement a validation process, comparing modeled performance and actual system performance during dynamic events. MOD-033-1: Steady-State and Dynamic System Model Validation

21. RELIABILITY | ACCOUNTABILITY21 Longer-Term Dynamics Comparison: Modeling Major Grid Disturbances

22. RELIABILITY | ACCOUNTABILITY22 Comparison of Transmission Interfaces & FACTS Outputs

23. RELIABILITY | ACCOUNTABILITY23 PRC-002-2 ensures “adequate data [is] available to facilitate analysis of Bulk Electric System (BES) Disturbances.”  Approved by FERC on September 17, 2015 “Identify BES Elements for which dynamic Disturbance recording (DDR) data is required, including:”  “Generating resource(s) with: o Gross individual nameplate rating greater than or equal to 500 MVA o 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.  Any one BES Element that is part of a stability (angular or voltage) related System Operating Limit (SOL).  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. PRC-002-2: Disturbance Monitoring and Reporting Requirements

24. RELIABILITY | ACCOUNTABILITY24  One or more BES Elements that are part of an Interconnection Reliability Operating Limit (IROL).  Any one BES Element within a major voltage sensitive area as defined by an area with an in-service undervoltage load shedding (UVLS) program.” “Identify a minimum DDR coverage, inclusive of those BES Elements identified…, of at least:”  “One BES Element; and  One BES Element per 3,000 MW of the Responsible Entity’s historical simultaneous peak System Demand.” PRC-002-2: Disturbance Monitoring and Reporting Requirements

25. RELIABILITY | ACCOUNTABILITY25 “Each [TO] shall have DDR data to determine the following electrical quantities…”  V: One phase-to-neutral or positive sequence voltage  I: Phase current (same phase & voltage) or positive sequence current  P/Q: 3φ MW and MVAR for each circuit where current measured  F: For any one of the voltage(s) “Each [GO] shall have DDR data to determine the following electrical quantities…”  V: One phase-to-neutral, phase-to-phase, or positive sequence voltage at either (GSU) high- or low-side voltage  I: Phase current (same phase & voltage), phase current(s), or positive sequence current  P/Q: 3φ MW and MVAR for each circuit where current measured  F: For any one of the voltage(s) PRC-002-2: Disturbance Monitoring and Reporting Requirements

26. RELIABILITY | ACCOUNTABILITY26 “Each [TO] and [GO] responsible for DDR data from the BES Elements…shall have continuous data recording and storage. If the equipment was installed prior to the effective date of the standard and is not capable of continuous recording, triggered records must meet the following…”  At east 3 minute recording length  One trigger type [specified] “Each [TO] and [GO] shall time synchronize all…DDR data…:  Synchronized to UTC with or without a local time offset  Synchronized device clock accuracy within +/- 2 ms of UTC PRC-002-2: Disturbance Monitoring and Reporting Requirements

27. RELIABILITY | ACCOUNTABILITY27 “Each [TO] and [GO] shall provide…DDR data…to the Responsible Entity, Regional Entity, or NERC in accordance with…:”  “Data will be retrievable for the period of 10-calendar days, inclusive of the day the data was recorded.”  “Data…will be provided within 30-calendar days of a request unless an extension is granted by the requestor.”  “…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.”  “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.” PRC-002-2: Disturbance Monitoring and Reporting Requirements

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