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2016-04 Modifications to PRC-025-1 | PRC-025-2

Description:

Start Date: 10/30/2017
End Date: 12/14/2017

Associated Ballots:

Ballot Name Project Standard Pool Open Pool Close Voting Start Voting End
2016-04 Modifications to PRC-025-1 PRC-025-2 AB 2 ST 2016-04 Modifications to PRC-025-1 PRC-025-2 07/25/2017 08/23/2017 12/04/2017 12/14/2017

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Hot Answers

David Jendras, Ameren - Ameren Services, 3, 12/14/2017

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LCRA Compliance, Segment(s) 1, 5, 6, 5/6/2015

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Other Answers

None

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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BHC feels the IP is reasonable. 

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

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Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Allow 36 months instead of 24 months for the added option per this revision. Generators with 24 month outage schedules will need the additional time, especially nuclear plants.

Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Mike Smith, Manitoba Hydro , 3, 12/1/2017

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Tom Haire, 12/4/2017

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AEP believes this most recently proposed Implementation Plan is reasonable.

 

Thomas Foltz, AEP, 5, 12/4/2017

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DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 12/6/2017

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Recommend providing the same 60-month and 84-month implemenation preiods no matter what aype of protective device, to avoid confusion.

Theresa Allard, Minnkota Power Cooperative Inc., 1, 12/6/2017

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Ann Carey, 12/7/2017

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The SDT should provide the same full 60 and 84 month phased-in implementation from the first effective date of PRC-025-2 for any protective devices that apply to footnote 1, of proposed PRC-025-2 (1 Relays include low voltage protection devices that have adjustable settings).  The SDT must allow entities appropriate time to adjust to changes in the NERC standard.

MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

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Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

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Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 4/13/2017

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Richard Jackson, U.S. Bureau of Reclamation, 1, 12/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 12/8/2017

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Cynthia Lee, Exelon, 5, 12/8/2017

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Rick Applegate, 12/8/2017

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 12/11/2017

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Laura Nelson, 12/11/2017

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Douglas Webb, 12/11/2017

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larry brusseau, On Behalf of: Corn Belt Power Cooperative, , Segments 1

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Kevin Salsbury, On Behalf of: Berkshire Hathaway - NV Energy, , Segments 5

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Mark Riley, Associated Electric Cooperative, Inc., 1, 12/11/2017

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Comments submitted as part of ACES comments

William Hutchison, On Behalf of: Southern Illinois Power Cooperative, , Segments 1

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Bette White, 12/12/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Support Comments submitted by the MRO NERC Standards Review Forum (NSRF)

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 12/12/2017

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Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

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Rachel Coyne, Texas Reliability Entity, Inc., 10, 12/13/2017

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SPP Standards Review Group, Segment(s) , 12/13/2017

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We appreciate the SDT’s inclusion of a transition period between implementation plans for this standard.  However, we find the phased-in approach based on varying options of relay loadability evaluation criteria confusing.  For load‐responsive protective relays that are currently subject to the standard, the current implementation plan could possibly supersede the proposed implementation plan.  We believe a phased-in implementation period should clearly begin on the effective date of the proposed standard and independent of specific relay loadability evaluation criteria.  If an entity determines that replacement or removal of the relay is not necessary, then the entity should have 24 months after the standard’s effective date to make other associated changes.  However, if the entity determines relay replacement or removal is necessary, then the entity should have 48 months after the standard’s effective date for procurement and installation of the new relay.  With the inclusion of the element 50 relay in this proposed standard, the SDT’s 60-month and 84-month respective implementation period is tolerable.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 12/13/2017

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Douglas Johnson, 12/13/2017

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FMPA, Segment(s) , 10/23/2017

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RSC no Dominion and ISO-NE, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 12/11/2017

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David Ramkalawan, 12/13/2017

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George Brown, Acciona Energy North America, 5, 12/13/2017

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Hot Answers

For figure 2, identify that busses B, C, and D and their interconnecting lines as 'the transmission system' for clarity.  We believe that this will help clarify that only reverse-looking or non-directional elements are within PRC-025 scope.

David Jendras, Ameren - Ameren Services, 3, 12/14/2017

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LCRA Compliance, Segment(s) 1, 5, 6, 5/6/2015

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Other Answers

None

Aaron Cavanaugh, On Behalf of: Bonneville Power Administration, WECC, Segments 1, 3, 5, 6

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

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Seattle City Light Ballot Body, Segment(s) 1, 4, 6, 5, 3, 12/2/2016

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Entergy/NERC Compliance, Segment(s) 1, 5, 3/1/2017

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Mike Smith, Manitoba Hydro , 3, 12/1/2017

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Section 4.2.5 should have a minimum threshhold.

 

Tom Haire, 12/4/2017

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Thomas Foltz, AEP, 5, 12/4/2017

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The Exclusions section should also exclude the following protection system based on footnote 1 in the Applicability Section: Low voltage protection devices that do not have adjustable settings.

DTE Energy - DTE Electric, Segment(s) 5, 4, 3, 2/27/2017

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Leonard Kula, Independent Electricity System Operator, 2, 12/6/2017

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Theresa Allard, Minnkota Power Cooperative Inc., 1, 12/6/2017

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Ann Carey, 12/7/2017

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MRO NSRF, Segment(s) 3, 4, 5, 6, 1, 2, 6/14/2017

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Xcel Energy has concerns that the changes to the "Application" column for Options 7a-7c, 8a-8c, and 9a-9c are somewhat misleading and the description is inconsistent with Figure 5.  We do acknowledge that this is partially a carryover issue from PRC-025-1.

The "Application" column for options 7, 8 & 9 describe "Relays installed on the generator side of the Generator step-up transformer..." Figure 5 shows that the current transformers for the load dependent relays to which options 7-9 are applicable are actually applied on the generator or the generator breaker and not specifically on the low side of the GSU.  Note that many microprocessor based generator protection relays allow you to select the signal source for the current input to the 21 function such that either neutral or line side current transformers may be used for the current signal input to the 21 device associated with the generator.  In other words, not all generator load dependent relays are fed neutral side current transformers.  From this perspective, it would be unclear whether the entity should be using option 1a-1c or option 7a-7c for evaluating the loadability of the 21 function or options 2a-2c or option 8z-8c for the 50/51 functions.

Note that on Figure 5, the location of the generator breaker relative to the generator bus tap to the UAT is incorrect for most typical applicactions.  In most applications when a generator breaker is provided, it will be on the generator bus between the generator and the bus tap to the UAT so that the UAT remains in service from the GSU when the generator breaker is open and the generator is offline.  There would be operational value in a generator breaker between the UAT tap and GSU LV winding as shown in Figure 5.  By moving the location of the generator breaker to the correct location between the generator and UAT bus tap on Figure 5, all inconsistency would be elimated and would greatly improve the clarity of the differences between options 1 vs. 7 and 2 vs. 8.  See attached file for markup of Figure 5.

Based on the criteria included in the "settings criteria" colum for options 1, 2, 7 & 8, the key difference to use when determining which option to use is dependent on if the current transformer feeding the load dependent relay includes measurement of current flowing to the UAT in addition to that flowing to the LV winding of the GSU from the generator. 

Beyond the above issue with the description clarity, we also have the following technical concerns with options 7 & 8 vs. options 1 & 2:

  1. In many instances, in addition to the unit connected auxiliary transformer, a plant also likely has a 100% power capable system connected auxiliary transformer.  In this case, the amount of power the plant would be capable of putting out would, to the system, be greater and the settings of any load dependent relay when the plant is fed from the system connected aus, should be based on that capability and calculated per option 1 or 2 and not for the lower value of aggregate power as allowed by option 7 or 8 - regardless of the location of the CT used to feed the load dependent relay.  If an entity's reported max gross MW value is based on the gross output when fed from the system connected auxiliary source, then the entity should have to use option 1 or 2 regardless of the configuration of the current transformer relative to the unit connected auxiliary transformer.  Option 7 or 8 should only be allowed if the max gross MW reported is based on the reduced output available when the unit is receiving auxiliary power from the unit connected auxiliary transformer.
  2. The differences in determining real power between options 1 and 2 vs. 7 adn 8 is understandable, but it is unclear why the reactive power used in option 7 & 8 are calculated differently than that used in options 1 & 2.  What is the technical justification for the difference?  The response of the machine to depressed grid voltages and field forcing capability will be the same regardless of where the load dependent relay current transformer is located relative to the aux power tap.  Using a reduced value for field forcing MVAR based on aggregate MW output rather than a MW value based strictly on nameplate MVA and rated pf does not seem justified.

 

 

Amy Casuscelli, On Behalf of: Xcel Energy, Inc. - MRO, WECC, SPP RE - Segments 1, 3, 5, 6

PRC-025 modifications drawing.docx

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By adding the phrase “except that” to “Elements 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, except that Elements may also supply generating plant loads.” in multiple places throughout the document, ambiguity is increased rather than decreased.  LKE suggests replacing these instances with full, clearly worded sentences.

Louisville Gas and Electric Company and Kentucky Utilities Company, Segment(s) 3, 5, 6, 4/13/2017

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Richard Jackson, U.S. Bureau of Reclamation, 1, 12/8/2017

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Glen Farmer, Avista - Avista Corporation, 5, 12/8/2017

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In the previous request for comments Exelon requested that the Project 2016-04 SDT evaluate the proposed fault detector settings associated with pilot wire communication systems.  Specifically, Exelon stated in the response to Question 2 that "[c]alculations performed to calculate the settings for these type of relays show that the settings are very close to the 3-phase fault current contributed from the generator in cases where sub-transient reactance of the machine is at a high value.  This will compromise the protection scheme because the changes proposed will make the protection scheme very insensitive. In case of a high resistance phase-to-ground fault, the protection scheme will not pick up the fault at the generator end.  In some extreme cases, the fault detector relay (67 or 50),  if set according to the current draft PRC-025 guidelines, may have to depend on the field forcing provided by the Automatic Voltage Regulator (AVR) before the fault current reaches the setpoint.  This will induce unnecessary delays in the protective action and may cause more damage to the BES element."

The SDT response to Exelon's comment was that this issue was "beyond the scope of the drafting team's work to revise PRC-025-1 as described in the SAR" and that an entity might have to "employ alternative protection schemes to achieve the loadability requirements and fault protection."  Exelon does not agree that this is outside the scope of the SAR given consideration item (2) in the SAR specifically states that this project is to address the inclusion or exclusion of the 50 element.

To address our concerns, Exelon requests the following changes:

  1. The fault detector relays used in communication systems should be deleted from the scope of this standard because these particular relays are subject to misoperation only when the communication system has failed and there is a concurrent disturbance on the grid. 
  2. If there is any issue with a communication system and if the whole pilot protection scheme becomes a simple overcurrent relay, that condition is alarmed.  Therefore, this condition would only exist for a short duration.  To fix this condition the SDT can add a requirement to remedy this condition within a certain timeframe (e.g., correct condition within three months) and if not resolved then setpoints of 67 or 50 should be raised.
  3. If the SDT still wants to retain these relays within the scope, then Exelon requests that the existing setting criteria should be modified as follows:
    1. “Minimum of the criteria 15a (or 15b) or 25% of the current contribution from the generator using a pre-fault voltage of 1.0 pu, generator sub-transient unsaturated reactance, and the main power transformer positive sequence reactance."

 

 

Cynthia Lee, Exelon, 5, 12/8/2017

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Question for drafting team:

“If a line connecting the GSU transformer(s) to the Transmission system has a load (that is not generating plant load) tapped to it, would Options 14, 15, or 16 apply at the remote end of the line?  Would it apply at the high-side of the GSU transformer(s)?

If the answer to both questions above is ‘no,’ then, if there are two lines connecting the GSU transformer(s) to the Transmission system, and one line has a load (that is not generating plant load) tapped to it, would Options 14, 15, or 16 apply at the high-side of the GSU transformer(s)?”

Rick Applegate, 12/8/2017

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Michelle Amarantos, APS - Arizona Public Service Co., 5, 12/11/2017

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Laura Nelson, 12/11/2017

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None

Douglas Webb, 12/11/2017

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larry brusseau, On Behalf of: Corn Belt Power Cooperative, , Segments 1

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Kevin Salsbury, On Behalf of: Berkshire Hathaway - NV Energy, , Segments 5

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Mark Riley, Associated Electric Cooperative, Inc., 1, 12/11/2017

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Comments were submitted as part of ACES Commnets.

William Hutchison, On Behalf of: Southern Illinois Power Cooperative, , Segments 1

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Bette White, 12/12/2017

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Neil Swearingen, On Behalf of: Salt River Project, WECC, Segments 1, 3, 5, 6

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Support Comments submitted by the MRO NERC Standards Review Forum (NSRF)

Darnez Gresham, Berkshire Hathaway Energy - MidAmerican Energy Co., 3, 12/12/2017

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We appreciate the drafting team’s consideration of our comments submitted on PRC-025-2, Draft 1.  We believe the drafting team’s response to our comment under Question 12 should be added as a footnote to Table 1.  Specifically, consider adding the following as a clarifying footnote to Table 1: “The “gross MW capability reported to the Transmission Planner” is based upon NERC Reliability Standard MOD‐025‐2.  The Generator Owner may base settings on a capability (e.g., nameplate) that is higher than what is reported to the Transmission Planner.  If different seasonal capabilities are reported, the maximum capability could be used for the purposes of this standard as a minimum requirement.”

Tennessee Valley Authority, Segment(s) 1, 3, 5, 6, 10/5/2015

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Attachment 1 states that relay setting criteria values are derived from the unit’s maximum gross Real Power capability, in megawatts (MW), as reported to the Transmission Planner. This does not account for the scenario when the Generator Owner (GO) does not provide accurate capability data to the Transmission Planner (TP). Texas RE suggests it would be more effective to base the Real Power capability on calculations used for the determination of Facility Ratings or the Real Power capability verification performed for MOD-025-2.

 

As previously requested, Texas RE asks the SDT consider providing a justification of the “Long Term Planning” time horizon as it has a significant impact on Penalty calculations. The phrase “shall apply settings” is indicative of a Real-time or near Real-time action.  While planning activities have to recognize proposed settings (and reflect current setting for those relays not subject to change), ultimately the setting occurs in a much shorter time horizon than “Long-term Planning”. 

 

Texas RE also noticed the following:

  • In the redline version, the header still has “-1” throughout some of the change management documents of the Standard.  Texas RE did notice the header was changed to PRC-025-2 in the clean version.

  • Section “C: Compliance 1.3 Compliance Monitoring and Assessment Processes” appears to not follow the template for Results Based Standards.  This version lists out the various compliance monitoring processes, whereas the template states:  As defined in the NERC Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated Reliability Standard.

  • The Violation Severity Level table does not follow the template for Results Based Standards. 

  • The introduction in Attachment 1, references “3.2 Facilities”.  Facilities are listed in section 4.2 of the standard.

Rachel Coyne, Texas Reliability Entity, Inc., 10, 12/13/2017

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N/A

SPP Standards Review Group, Segment(s) , 12/13/2017

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  1. We believe a performance-based criteria could be established for the Violation Severity Levels (VSLs) for this standard, similar to what is present for NERC Reliability Standard PRC-005-6.  In that standard, the severity is based on a specific percentage of Components the applicable entity failed to maintain in accordance with minimum maintenance activities and maximum maintenance intervals.  In this standard, a severe VSL is assessed when the entity fails to apply the required settings for any one load‐responsive protective relay.  We recommend a gradated approach based on the percentage of load-responsive protective relays where the entity failed to apply settings.  This would complement the list of load-responsive protective relays identified as requested evidence in the standard’s RSAW.
  2. We ask the SDT to include hyperlinks for documents referenced as footnotes. The presence of multi-lined web addresses can inadvertently include extra spaces that corrupts or disables the link.
  3. We thank you for this opportunity to provide these comments.

ACES Standards Collaborators, Segment(s) 1, 5, 3, 12/13/2017

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No comments. 

Douglas Johnson, 12/13/2017

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It would seem that item number 5 of the SAR was not completed.  For example, the setting criteria for Table 1 still has language such as “…shall be set less than the calculated impedance derived from 115% of: ….”

From item number 5 of the SAR, “Clarify that multiple methods/curve types are acceptable so long as the applied protection does not trip the generator(s) under the conditions described in the table. For example, using such language could more clearly allow use of blinders, non‐mho relay characteristics and other schemes in which the relay’s initial measurement may detect a condition (e.g., may “pickup”) but the relay is blocked from operating.”

Since the Table 1 descriptors still refer to an “impedance element setting”, the issue still exists despite removing the term “Pickup”, which was only part of what was needed. Using the phrase “shall not trip” rather than the phrase “shall be set” in the Table 1 Setting Criteria will accomplish the goal of item number 5. Due to the SAR not being complete, FMPA is casting a negative ballot.

FMPA, Segment(s) , 10/23/2017

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RSC no Dominion and ISO-NE, Segment(s) 10, 2, 4, 5, 6, 7, 1, 3, 12/11/2017

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David Ramkalawan, 12/13/2017

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First, the PRC-025 Standard Drafting Team (SDT) has done an excellent job of addressing application 5B as it relates to dispersed power producing resources.  However, I still have a concern how PRC-025 is applied to other equipment at the generation asset.  My concern is in relation to equipment that is not designed to operate at 130% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor and this equipment is at a facility that was built prior to PRC-025 becoming effective/enforceable.  My specific concern relates to the following Applications and Options in Attachment 1, Table 1.

  • Application: Relays installed on generator‐side of the Generator step‐up transformer(s) connected to asynchronous generators only (including inverter-based installations).
  • Options: 10, 11 & 12

 

  • Application:  Relays installed on the high‐side of the GSU transformer,15 including relays installed on the remote end of line, for Elements 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. (except that Elements may also supply generating plant loads.) – connected to asynchronous generators only (including inverter-based installations).
  • Options: 17, 18 & 19

For example, let’s say that a dispersed power producing resource’s main power transformer (MPT) is only rated to run continuously at 110% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor or what is better known as a original equipment manufacturer damage curve.  If an entity was to set its respective protection systems for that MPT to ≥ 130% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor then the MPT is no longer properly protected, has become a safety issue for personnel that work around the MPT and at risk of catastrophic failure. 

I would like to recommend the SDT add similar language as drafted for application 5B to Options 10, 11, 12, 17, 18 & 19.  Perhaps, even taking it a step further and adding in some sort of “grandfathering” language, so that facilities that are connected/constructed after the effective/enforcement of PRC-025 would be designed to meet the 130%, while facilities built prior can have their protection systems set to the maximum allowable level based on the equipment installed at the facility. 

Essentially, there is potential that many dispersed power producing resources will have equipment throughout the site that will not allow them to set protection systems to ≥ 130% of the calculated current derived from the maximum aggregate nameplate MVA output at rated power factor while still providing adequate protection to the equipment necessary for the safe and reliable operation of the facility.

George Brown, Acciona Energy North America, 5, 12/13/2017

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