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2021-04 Modifications to PRC-002-2 | IRPTF SAR

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Start Date: 06/14/2021
End Date: 07/13/2021

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Hot Answers

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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Other Answers

No comment

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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Donald Lock, On Behalf of: Talen Generation, LLC, , Segments 5

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Duke Energy does not have comments at this time.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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AEP believes there may be benefit in pursuing this SAR, however we do not believe that the burden to install SER, FR, and DDR should be placed on the Transmission Owner. Rather, any such obligations to do so should be placed solely on the Generator Owner of those resources.

We believe Attachment One should be revised to make it absolutely clear that it governs Transmission assets only. Generation resources deserve their own distinct selection criteria for R1 and R3, one that is inclusive of both synchronous generation and inverter based generation. Generator Owners should be able to make their determination on which assets require FR and SER solely on the resource in question, and not based on analysis regarding how that asset is compared to others. One suggested method to consider would be establishing individual and aggregate thresholds for when SER and FR would need to be installed.

While both the IRPTF SAR and the Glencoe Power and Light SAR each focus on revising PRC-002, their perceived needs and expressed goals are quite different. Because only one single SAR governs a project at any point in time, and because the unique efforts for the IRPTF SAR will likely be met with much more resistance than the Glencoe SAR, AEP recommends breaking this project into multiple phases, each with its own SAR governance. The Glencoe SAR will likely encounter less resistance from industry than the IRPTF SAR, so we recommend that the Glencoe SAR govern the first phase of the project. Once that phase is complete, the second phase could then begin with the IRPTF SAR governing Phase 2. Pursuing Project 2021-04 this way would be much more efficient, allow progress to be made more quickly on the purpose and goal on the Glencoe SAR, and without potential delay associated to any resistance to efforts related to the IRPTF SAR.

Thomas Foltz, On Behalf of: AEP, , Segments 3, 5, 6

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Step 8 in Attachment 1 for R1 already provides a means by which bus locations not captured in the highest 10% bus fault current calculations are selected for SER and FR data monitoring to achieve the 20% total. Locations with Inverter Based Resources can be added to the list of recommended locations.

MRO NSRF, Segment(s) 2, 4, 1, 6, 3, 5, 7/1/2021

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N/A

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Donna Wood, On Behalf of: Tri-State G and T Association, Inc., , Segments 1, 3, 5

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FE Voter, Segment(s) 1, 3, 5, 6, 4, 2/23/2021

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The rationale for R1 on page 22 explains in detail the data analysis efforts which have gone into developing a methodology for identifying optimum number of buses. The study established a strong correlation between the short circuit MVA level available at a bus and its relative size based on voltage level, no. of transmission lines and other BES elements connected have an impact on system reliability. BES buses with a large short circuit MVA level are BES Elements that have a significant effect on System reliability and performance. Conversely, BES buses with very low short circuit MVA levels seldom cause wide-area or cascading System events, so SER and FR data from those BES Elements are not as significant. After analyzing and reviewing the collected data submittals from across the continent, the threshold MVA values were chosen to provide sufficient data for event analysis using engineering and operational judgment. Though entities could cover the inverter-based resources under optional buses in Step 8 of the algorithm in attachment 1 of the standard.

Dwanique Spiller, On Behalf of: Berkshire Hathaway - NV Energy - WECC - Segments 5

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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AZPS does not support the scope of the SAR submitted by the NERC Inverter-based Resource Performance Task Force (IRPTF) because is too broad and does not provide specific information on the changes to be addressed by the standard drafting team.  Additionally, AZPS does not agree that the IRPTF White Paper provides sufficient justification for revising the standard.  AZPS’s experience has shown that any significant inverter based resources tie into large substations for which the MVA requirement would cover the need for monitoring. 

Daniela Atanasovski, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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The existing standard targets BES elements with short circuit MVA in the top 20% which could leave out inverter-based resources. Recent events involving inverter-based resources (IBR), such as the Blue Cut Fire and Canyon 2 Fire, have demonstrated the need to monitor some inverter-based resources. The Project 2021-04 SAR (the portion written by the IRPTF) addresses the need to monitor some IBRs.

Anthony Jablonski, On Behalf of: ReliabilityFirst , , Segments 10

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Lindsay Wickizer, On Behalf of: Berkshire Hathaway - PacifiCorp, , Segments 6

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Allie Gavin, On Behalf of: International Transmission Company Holdings Corporation - MRO, RF - Segments 1

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The City of Tallahassee (TAL) believes that requiring additional monitoring equipment is not cost-effective given the minor contribution to the BES in terms of fault current.  TAL is unsure how the data collected will provide a substantial gain to the BES.

Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

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Reclamation agrees with the addition of a requirement to further enhance SER/FR and DDR equipment in facilities on the premise that the information obtained not only enhances BES reliability but also enhances an entity’s ability to troubleshoot and repair Facilities, further reduce operating costs, and increase reliability. Reclamation recommends the scope of the SAR also include the items described in the response to Question 2.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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BPA disagrees with this project scope. PRC-002-2 Attachment 1, Step 8 already says “the additional BES buses are selected, at the Transmission Owner’s discretion, to provide maximum wide-area coverage for SER and FR data.” It then provides recommendations for selecting additional bus locations. We do not only rely on PRC-002-2 to require disturbance monitoring and recording. We have our own requirements for when to install disturbance monitoring and recording and the TO should know their system well enough to know when and where they need to monitor. In order to completely eliminate the possibility of not having data available for event analysis, you’d have to require monitoring and recording at every substation which may or may not be possible. The SAR mentions the IBRs don’t provide enough fault current, thus they can contribute to a fault. PRC-002 is for wide area faults and reconstructing them. This SAR may be better applied to PRC-023 or another protection standard. The owners need to update their own standards for SER/FR equipment or at least protective systems (most offer both limited SER/FR capability).

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Evergy supports and incorporates by reference Edison Electric Institute’s (EEI) response to Question 1.

Alan Kloster, On Behalf of: Great Plains Energy - Kansas City Power and Light Co. - MRO - Segments 1, 3, 5, 6

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Capital Power (CP) (on behalf of Decatur Energy Center LLC and other MRRE group 80 assets) supports the NAGF submitted comments on this item. 

Shannon Ferdinand, On Behalf of: Decatur Energy Center LLC, , Segments 5

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EEI supports the concerns identified in the IRPTF SAR that current processes contained within PRC-002-2 (Attachment 1) used to identify BES buses where sequence of event (SER) and fault recording (FR) equipment are to be installed generally do not require the placement of this equipment on buses where IBR resources are prevalent. The SAR SDT should consider the potential fault recording differences that may be required by IBRs, such as the possible need for faster sampling rates for IBRs, while providing little value for synchronous resources.  EEI also suggests SER and FR equipment might be efficiently placed at the point of aggregation where this information would be more useful. 

Additionally, given the parallel posting of both the IRPTF and Glencoe Light SARs, consideration should be given to addressing these two SAR under a single project but through a multi-phased approach with the Glencoe Light scope SAR being addressed in the first phase. 

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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Hot Answers

Brad Harris, On Behalf of: CenterPoint Energy Houston Electric, LLC, Texas RE, Segments 1

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Rachel Coyne, On Behalf of: Texas Reliability Entity, Inc., , Segments 10

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Other Answers

Carl Pineault, On Behalf of: Hydro-Qu?bec Production, , Segments 1, 5

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PRC-002-2 says in Requirement R1.2 that TOs shall, “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.”  The expression “and/or” suggests that the two forms of DME might not be automatically conjoined; there could be cases in which need to install SER does not mean that FR is required also.  This point is left hanging, though, in the PRC-002-2 Att. 1 methodology for selecting buses.  The rules apply to, “SER and FR data,” together, not individually.

The issue is not clarified until one gets to the Rationale section of PRC-002-2, which confirms that there are SER-but-not-FR exceptions, “Generator step-up transformers (GSUs) and leads that connect the GSU transformer(s) to the Transmission System that are used exclusively to export energy directly from a BES generating unit or generating plant are excluded from Requirement R3 because the fault current contribution from a generator to a fault on the Transmission System will be captured by FR data on the Transmission System, and Transmission System FR will capture faults on the generator interconnection.” 

Talen Energy proposes that the FR exemption for GSUs and GSU-to-TO HV lines be stated in the Applicability section of PRC-002-3.  The Rationale section of the standard should explain but not modify the Requirements section.

Donald Lock, On Behalf of: Talen Generation, LLC, , Segments 5

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Duke Energy does not have comments at this time.

Duke Energy, Segment(s) 1, 5, 6, 4/11/2019

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Maryanne Darling-Reich, On Behalf of: Black Hills Corporation - MRO, WECC - Segments 1, 3, 5, 6

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Thomas Foltz, On Behalf of: AEP, , Segments 3, 5, 6

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Expand the scope to add an implementation period for newly identified BES buses. During five year reviews, new BES buses are identified, and particularly in the case of BES buses like ones that may be identified as a result of this SAR that are interconnected at remote areas of the system, DDR equipment may not already be on-site and will need to be designed, procured, and installed.   

MRO NSRF, Segment(s) 2, 4, 1, 6, 3, 5, 7/1/2021

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N/A

Leonard Kula, On Behalf of: Independent Electricity System Operator, , Segments 2

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Donna Wood, On Behalf of: Tri-State G and T Association, Inc., , Segments 1, 3, 5

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N/A

FE Voter, Segment(s) 1, 3, 5, 6, 4, 2/23/2021

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The proposal from IRPTF does not address following issues, which the Standards Drafting Team (SDT) should consider.

  • The requirement R1.1 should address step 8 of the algorithm in attachment 1 of the standard. For example, step 8 does not necessarily include the case of growing inverter-based resource monitoring. It has been noticed that while applying step 1-step7, the applicable buses tend to concentrate in the high MVA zones and distributed monitoring across the network does not occur. The standard or the algorithm need to be tweaked to address this issue.
  • The algorithm could adopt the weighted points technique considering MVA, Voltage, NO. of lines, IROL (Interconnection Reliability Operating Limit) and SOL (Stability Operating Limit), UVLS schemes, and Vegetation parameters to derive a distributed FR/SER/DDR monitoring.
  •   Standard should address follow through action by notified entities participating in interconnection with the notifying entity in a time bound way to ensure adequate FR/SER/DDR monitoring in zones, where multiple entities are involved.  DDR notification by Reliability Coordinators (RC) should have more details justifying the DDR requirement than merely quoting the requirement nos. in the notification document.

Dwanique Spiller, On Behalf of: Berkshire Hathaway - NV Energy - WECC - Segments 5

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David Jendras, On Behalf of: Ameren - Ameren Services, , Segments 1, 3, 6

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None

Daniela Atanasovski, On Behalf of: APS - Arizona Public Service Co., , Segments 1, 3, 5, 6

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Anthony Jablonski, On Behalf of: ReliabilityFirst , , Segments 10

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Lindsay Wickizer, On Behalf of: Berkshire Hathaway - PacifiCorp, , Segments 6

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Allie Gavin, On Behalf of: International Transmission Company Holdings Corporation - MRO, RF - Segments 1

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Scott Langston, On Behalf of: Tallahassee Electric (City of Tallahassee, FL), , Segments 1, 3, 5

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Reclamation recommends the PRC-002 SAR include provisions to modify Section 4.1, Requirement R1, Requirement R5, and Requirement R12 to address the following items:

  • In the Western Interconnection, entities also receive notifications from the Planning Coordinator. Therefore, Section 4.1.3 should be revised to include Planning Coordinators.
  • Requirement R1.3 should be modified to state the timeframe within which entities must be compliant with R2, R3, R4, R10, and R11 for any equipment added as a result of the TO’s re-evaluation (i.e., within 3 years following the notification by the TO).
  • Requirement R5.4 should be modified to state the timeframe within which entities must be compliant with R6, R7, R8, R9, R10, and R11 for any equipment added as a result of the Responsible Entity’s re-evaluation (i.e., within 3 years following the notification by the Responsible Entity that re-evaluated the list). Alternatively, each requirement (R6 through R11) should state the time period after notification within which the required activity must be completed as a result of changes to the TO’s or Responsible Entity’s list.

  • Reclamation recommends adding the sharing of protection system data when requested by the entity performing the R1 evaluation.

  • Requirement R12 should be modified to add a required time limit within which to notify the Regional Entity(ies) of a failure of the recording capability. Regional Entities need to know as soon as the failure occurs or is discovered, not up to 90 days later.

Richard Jackson, On Behalf of: U.S. Bureau of Reclamation, , Segments 1, 5

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In general, PRC-002 is loosely written. BPA has submitted questions to WECC for clarification. R4.3 states “Trigger settings for at least the following: 4.3.1 Neutral (residual) over current. 4.3.2 Phase undervoltage or overcurrent”; this can be interpreted that the XFMR can have a phase undervoltage trigger even though R3 states: “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.” 

Andrea Jessup, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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Evergy supports and incorporates by reference Edison Electric Institute’s (EEI) response to Question 2.

Alan Kloster, On Behalf of: Great Plains Energy - Kansas City Power and Light Co. - MRO - Segments 1, 3, 5, 6

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Capital Power (CP) (on behalf of Decatur Energy Center LLC and other MRRE group 80 assets) supports the NAGF submitted comments on this item. 

In addition, CP supports Reclamation’s recommendation of the following (modified slightly):

PRC-002 SAR should include provisions to modify Section 4.1, Requirement R1, Requirement R5, and Requirement R12 to address the following items:

  • In the Western Interconnection, entities also receive notifications from the Planning Coordinator. Therefore, Section 4.1.3 should be revised to include Planning Coordinators.
  • Requirement R1.3 should be modified to state the timeframe / implementation period within which entities must be compliant with R2, R3, R4, R10, and R11 for any equipment added as a result of the TO’s re-evaluation (i.e., within 3 years following the notification by the TO).
    • This is particularly important when it comes to newly identified BES buses in remote areas where DDR equipment may not already be on-site and will need to be designed, procured, and installed.
  • Requirement R5.4 should be modified to state the timeframe within which entities must be compliant with R6, R7, R8, R9, R10, and R11 for any equipment added as a result of the Responsible Entity’s re-evaluation (i.e., within 3 years following the notification by the Responsible Entity that re-evaluated the list). Alternatively, each requirement (R6 through R11) should state the time period after notification within which the required activity must be completed as a result of changes to the TO’s or Responsible Entity’s list.
  • The addition of a requirement allowing exemption based on equipment limitation, age of asset etc. If a newly identified BES Bus happens to be connected to an existing asset nearing the end of its useful life, the cost / benefit of the installation of additional DDR equipment should be considered.

Shannon Ferdinand, On Behalf of: Decatur Energy Center LLC, , Segments 5

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EEI looks forward to reviewing a future Project 2021-04 SAR, which contains elements of both SARs.

Mark Gray, On Behalf of: Edison Electric Institute, NA - Not Applicable, Segments NA - Not Applicable

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