gridex program - nerc.com reliability subcommittee ors 20… · september 9, 2014 ... • rtca...

GridEx ProgramGrid Security Exercise

Bill Lawrence, Senior Manager of Critical Infrastructure Protection Awareness

Operating Reliability Subcommittee

September 9, 2011

Presentation 1

RELIABILITY | ACCOUNTABILITY2

GridEx 2011

GridEx II

2013

GridEx III 2015

18-19 November

GridEx – A Long-Term View

The purpose of the GridEx Program is to strengthen capability to respond to and recover from severe events

Continuing evolution

• Exercising timely, real-world scenarios

• Increasing stakeholder participation and training value

• Increasing integration with BPS operations

• Greater state/provincial and local government participation

• Greater integration with U.S. and Canadian senior executives and government officials

• Including other most critically interdependent infrastructure sectors

• Increasing interactive simulation into joint simulation


1. Exercise crisis response and recovery

2. Improve communication

3. Identify lessons learned

4. Engage senior leadership

GridEx III Objectives


Distributed Play Participation

GridEx 2011 had 420 individual participants compared to GridEx II with 2,000

42

115

19

97

914

6 8

0

20

40

60

80

100

120

140

GridEx 2011 (76) GridEx II (234)

GridEx Participating Organizations Comparison

Utilities

Government/Academia/Other

Reliability Coordinator/Independent System Operator

NERC Regional Entity


GridEx II Distributed Play


Proposed GridEx III Distributed Play


GridEx III Scenario Escalation Timeline


Critical Infrastructure Protection Committee (CIPC):

• Electricity Subsector Information Sharing TF (ESISTF)

• Security Training Working Group (w/ ESISTF)

• Control System Security Working Group (CSSWG)

• Business Continuity Guideline TF

•Grid Exercise Working Group (GEWG)

Electricity Subsector Coordinating Council (ESCC):

• Incident Response Playbook

• Cross-sector Coordination

• Public Affairs Coordination

• Advanced Cyber Preparation

• Spare Equipment

Addressing GridEx II

SPP Reliability:Proxy Report

ORS Meeting

Vancouver, WA

September 9, 2014

Robert Rhodes

[email protected] 501‐614‐3241

Proxy Flowgates for this Period:

2

Statistics from April 15, 2014 – August 31, 2014

Flowgate (5022): LaCygne-Neosho 345kV ftlo Emporia EC-Wichita 345kV

Flowgate (5221): Red Willow – Mingo 345kV

Flowgate (6009): Cooper South 345kV

Flowgate (6104): Iatan – Eastown 345kV

Flowgate (6126): Sub 1226 – Tekamah 161kV ftlo Sub 3451 – Raun 345kV

Flowgate (6146): Tekamah-Raun 161kV ftlo Sub3451-Raun 345kV

Presentation 2

FG 5022 – LaCygne‐Neosho 345kV ftlo Emporia EC‐Wichita 345kV

TLR DATE Return To Zero TLR Level

6/12/2014 12:00 6/12/2014 15:25 3


• Temporary Proxy for

• RTCA contingency Paola‐Centennial 161kV ftlo SE_OTTOWA‐W.Gardner 161kV

• RTCA contingency Paola‐Centennial 161kV ftlo LaCygne‐Neosho 345kV

• Neosho‐Caney River 345kV unplanned outage

4

5

Proxy Elements

Monitored Elements


Line Outage

Proxy Elements

FG 5221 – Red Willow‐Mingo 345kV


6/03/2014 01:00 6/03/2014 03:00 3

6/20/2014 06:00 6/20/2014 08:50 3

6/22/2014 09:00 6/22/2014 10:00 3

6/22/2014 13:00 6/22/2014 17:00 3

6/30/2014 16:00 6/30/2014 20:00 3



• FG 5466 Hays‐Vine 115kV ftlo Post Rock‐Knoll 230kV

• Maintaining voltage on the 115kV system around Mingo during times of heavy north‐south flows

• Due to

• Heavy north‐south flows

• Post Rock‐Spearville 345kV out of service 6/1‐6/14 due to weather event

• Post Rock‐Axtell 345 kV out of service 6/14‐20/14 due to weather event

7

8


Proxy Elements Red Willow-

Mingo 345kV

Monitored Elements

115kV system @ Mingo

Line Outage

FG 6009 – Cooper South


05/10/2014 16:45 5/10/2014 18:00 3

05/11/2014 15:00 5/11/2014 16:30 3



• Heavy north‐south flows

• RTCA contingency Kelly‐Tecumseh Hill 161kV ftlo Cooper‐St Joe 345kV

• RTCA contingency Hoyt‐Hoyt Jct South 115kV ftlo Hoyt‐Stranger Creek 345kV

• RTCA contingency Beatrice‐Harbine 115kV ftlo Cooper‐St Joe 345kV

10


Proxy Elements

Monitored Elements

Beatrice-Harbine115kV

Hoyt-Hoyt Jct S 115kV

Kelly-Tecumseh 161kV

Cooper- St Joe 345kV

Cooper- Fairport 345kV

FG 6104 – Iatan‐Eastown 345 kV


7/07/2014 10:00 7/07/2014 13:50 3



• Controlling Real‐time loading on Iatan‐Eastown 345kV line

• FG 5533 Eastown‐Eastside 161kV ftlo St Joe‐Eastown 345kV

• Heavy south‐north loading, high load in Nebraska area


Monitored Elements

Proxy Element

FG 6126 – Sub 1226‐Tekamah 161kV ftloSub 3451‐Raun 345kV


6/09/2014 15:00 6/09/2014 19:00 5

FG 6126 – Sub 1226‐Tekamah 161kV ftlo Sub 3451‐Raun 345kV


• RTCA contingency Sub 1226‐Tekamah 161kV ftlo Shell Creek‐Hoskins 345kV

• RTCA contingency Sub 1226‐Tekamah 161kV ftlo Rolling Hills‐Madison County 345kV (MISO)

• Ft. Calhoun‐Raun 345kV line out of service due to storm damage

FG 6126 – Sub 1226‐Tekamah 161kV ftlo Sub 3451‐Raun 345kV

17

Monitored Elements

Proxy Element

Tekamah

Hoskins

Shell Creek

Raun

Ft Calhoun

Line Outage

FG 6146 – Tekamah‐Raun 161kV ftlo Sub 3451‐Raun 345kV


6/05/2014 14:00 6/05/2014 18:00 3

6/06/2014 12:00 6/06/2014 19:00 5


• RTCA contingency Tekamah‐Raun 161kV ftlo Shell Creek‐Hoskins 345kV

• Columbus Hydro‐Creston 115kV ftlo Shell Creek‐Hoskins 345kV

• Ft. Calhoun‐Raun 345kV line, Oakland‐Tekamah and Oakland‐Winslow 115kV lines out of service due to storm damage

• External generation (Neal) trip increased flows on above constraints

19


20

Monitored Element

Proxy Element


Line Outage

Hoskins

Shell Creek

Tekamah

Raun

Ft.Calhoun

Creston

Columbus

Palmyra 345/161 kV Transformer Loading and Mitigation

NERC ORS Meeting 9/9/2014 AECI & MISO presentation

1

Jeff Harrison - AECI Phil Hart – AECI Kevin Larson – MISO Michael McMullen - MISO

Presentation 3

Why are we here? • Palmyra is an area of the AECI System, which

frequently experiences loading, requiring close coordination between AECI, TVA and MISO.

2

Why the NERC ORS? • ORS Scope:

– Provide oversight of tools and services that facilitate operational reliability

– Coordination between IDC Steering Committee and the NERC OC

– Provide a forum for coordination of TLR business practices and reliability standards

• NAESB Standards (WEQ-008): – Established TLR impact threshold at 5% – The RC initiating a Curtailment shall identify for Curtailment all

Firm Transmission Services (i.e. PTP, NIST, and service to NL) that contribute to the flow on any Constrained Facility or Flowgate by an amount greater than or equal to the Curtailment Threshold on a pro rata basis.

3

Why the NERC ORS? • Minutes from May 2014 ORS meeting

– September 2014 agenda to include this topic • IDCWG

– May ORS meeting minutes reflect that the ORS Chair would ask the IDCWG to assess and investigate this are for modeling accuracy.

• The model has subsequently been confirmed as accurate. – June IDCWG Meeting – AECI presented information on

Palmyra loading. IDCWG asked for more data. – August IDCWG Meeting - IDCWG requests this topic be on

the ORS agenda as it is outside their area of authority to mandate use of multi-monitored element (MME) flowgates or to change the 5% TLR threshold.

4

Why are we here? AECI Point MISO Point

AECI believes that not only are there reliably risks for Palmyra, but that also this example shines light on possible risk that could be present in many other areas of the interconnection. The IDCWG recognizes that they don’t have authority to change the 5% threshold and that this is an area where the ORS may be able to provide input and/or direction.

The coordinated operating guide and TVA/MISO RC to RC agreement provide for local congestion management solutions which have proven to be effective at maintaining reliability. The 5% threshold is under the purview of NAESB. The ORS should not consider permitting a MME FG to circumvent this standard. This threshold was created to avoid regional reliability impacts from constraints that should be managed with local procedures.

5

Background

• What/Where is Palmyra – The Palmyra 345/161 kV transformer is owned by

Associated Electric Cooperative’s (AECI) member, Northeast Electric Power Cooperative and located in Northeast Missouri off the Ameren Spencer Creek – Palmyra – Sub T 345 kV line. Flow impacts below the %5 TLR threshold can create challenges which requires coordination with MISO when congestion is experienced on this transformer.

6

7

Ameren

AECI

ITC AECI Ameren Ameren

So what's the problem? • Due to area geography (Mississippi River to the East)

limited paths are available to transfer power east. During some events it is not uncommon to see as much as 70% of the transformer rating being utilized to move power east into Illinois (Palmyra to North Marblehead 161 kV line). This issue creates further complications with implementing identified reconfiguration options.

• Historical analysis has shown that during periods of elevated loading on this transformer, on average, 80% of the transformer rating has been due to MISO market flows. The majority of these flows are below the 5% TLR threshold. Due to this, TLR is not always an effective method to reduce loading, requiring local area congestion management procedures.

8

So what's the problem? AECI Point MISO Point

Due to AECI having a small percentage of flows on this transformer, which is owned and maintained by AECI, and the lack of AECI generation having a meaningful impact on the flowgate, we do not feel that we should be obligated to provide relief outside of the TLR process to curtail tagged imports and exports having an impact on this Flowgate. To date there has not been a documented solution that provides AECI confidence that reliability can be preserved without the declaration of an emergency.

While MISO has been willing to go beyond the industry standards via proposed redispatch agreement, AECI’s statements that they don’t feel they should provide relief basically means that they feel that all parallel flows should be removed prior to them taking actions which is not consistent with NAESB TLR standards related to parallel flows. The ORS should not consider permitting a MME FG to circumvent this standard.

9

History • June 2012

– Load Shed Request issued to AECI for Loading in the Palmyra Area • July 2012

– Permanent Flowgates for the Palmyra Transformer added and coordinated with MISO and SPP

• July 2013 – Additional Flowgates coordinated with MISO for Market Flow

Reporting • August 2013

– Five TLRs on the Palmyra Flowgate • January 2014

– MME Flowgate Accepted and Passed for Coordination – Flowgate included in Palmyra Op-Guide Revision 0 of the RC

coordinated guide for Palmyra.

10

History • February 2014

– 6 TLRs on the Palmyra Flowgate. All events were ultimately mitigated without load shed.

• March 2014 – Flowgate 2658 begins Reporting Market Flow

• April 2014 – MISO terminated reporting of market flow on FG2658

• May 2014 – Palmyra Transformer returns to service, TLR issued

5/5/2014 – May 2014 ORS

11

What's Happened Since the May ORS

• Revised Operating Guide approved August 26th 2014. – Use Short Term rating. Note that the Short Term

rating has duration and pre-loading limitations. – Transmission reconfiguration. – ORCA process. – Test TLR. If relief is available then implement TLR. – Generation re-dispatch

12

Revised Operating Guide

AECI Point MISO Point Even with this Operating Guide, AECI is not confident that effective mitigation of market flows are guaranteed as discussions continue to explore other options. AECI is requesting the ORS to allow/enforce (whatever their authority will permit) the creation of a MME, with standard practice market coordination, to be used to control flows on this transformer.

The ORS should not consider permitting the use of a MME FG to circumvent NAESB standards associated with the TLR process. If such MME FG where used there could be broader reliability impacts due to curtailing schedules above 5% that do not have greater than 5% impact on the actual transformer.

13


• June 17th IDCWG – The committee agreed there appeared to be a

large market issue here; however additional data should be provided to confirm this issue exists repeatedly and consistently.

– If the data is sufficient, then the IDCWG will recommend the use of a MME (or interface) Flowgate in the IDC to manage congestion.

– The IDCWG did not find an technical or modeling issues based on the review of data.

14


• August 26th IDCWG – AECI provided summary of historical loading on the Palmyra Transformer,

including not only events during high loading of this unit but random samples to get an overall representation of typical flows and market flows.

– IDCWG Chair spoke with the IDC SC and they said there is nothing that prevents a proxy being created, however there is nothing that forces the other party to comply. It should be the RC who owns the flowgate who enforces and the other RC should comply. IDCWG recognized that they don’t have authority over TLR thresholds and indicated that the issue may be better addressed at the ORS. The group was reminded that the ORS directed the issue to the IDCWG for a technical review.

– From data provided the IDCWG acknowledges that there is flow on the system, majority is not curtailable, and that this can happen. From their prospective this is a problem, proxy may work, but this must be decided by the ORS (or other body) and not the IDCWG.

– IDCWG Chair recommends this go to the ORS. IDCWG requests AECI presents data to the ORS. IDCWG provides this technical input ‘that this can happen, most flows below 5%, and it cannot be controlled using TLR, what do you do?’

15


• Redispatch Agreement Concept discussion – 6/4/14 Redispatch agreement concept sent from

MISO to AECI – 9/2/14 Conference call between MISO and AECI to

discuss – MISO and AECI have another conference call

scheduled to continue discussions.

16


• Summary of Palmyra TLR Events since last ORS

17

FGID Start Date Time Stop Date Time 1030 5/21/2014 7:45 5/21/2014 23:15 1030 5/27/2014 11:25 5/27/2014 22:30 1030 6/3/2014 15:45 6/30/2014 23:00 1030 7/8/2014 8:45 7/8/2014 18:30 1030 7/10/2014 13:10 7/10/2015 22:35 1030 7/14/2014 14:10 7/14/2014 20:00 1031 5/20/2014 10:10 5/30/2014 18:25 1031 7/7/2014 7:45 7/8/2014 1:05 1031 9/2/2014 13:10 9/2/2014 16:50

18

0

50

100

150

200

250

300

350

400

450

FG 1030 – Palmyra Transformer for the loss of Thomas Hill to Adair FG 1031 – Palmyra Transformer for the loss of Sub T to Hills

5/6/14 9/6/14

19

0

50

100

150

200

250

300

350

400

450

9:36:00 10:48:00 12:00:00 13:12:00 14:24:00 15:36:00 16:48:00 18:00:00 19:12:00 20:24:00 21:36:00Time (EST)

9/02/14 FG 1031- Palmyra 345/161kV xfmr (FLO) Hills - Sub T - Louisa 345kV

Post Contingent Flow

Pre Contingent Flow

Normal Limit(336MVA)

Short Term Limit (370 MVA)

15:30 TLR 5B Effective

MISO's response

17:03 Ameren Spencer Creek V3 and V7 opened per coordinated op guide

18:43 Spencer Creek V3 and V7 closed AECI short term rating reset

MISO RTCA results < 85% due to

reconfiguration

Actions/Requests for the ORS/ Conclusions

AECI Point MISO Point

AECI will continue to work with MISO on options to control flows in this area, However an MME should be added as an approved option in the TLR process (step 4 of the current Operating Guide). If the first 3 steps of this guide work to control flows then the TLR on the MME FG will not be called.

The current operating guide provides for local congestion management solutions that are effective and more efficient than the MME FG. The MME FG is an attempt to circumvent NAESB standard 5% TLR threshold and how parallel flows are handled in the TLR process and should not be used.

20

Topic: MME

Actions/Requests for the ORS/ Conclusions

AECI Point MISO Point

As we see changes on the horizon due to generation retirement and other factors that change how we have historically seen generation dispatched in the interconnection (i.e. changes in gas prices, availability of fuels, markets). It would be prudent to ensure that the reliability tools and practices are capable of meeting the challenges that could be presented in the future or that may exist today in an N-2 scenario.

The 5% threshold and parallel flow priority in the TLR process is under the purview of NAESB. The ORS should not consider permitting a MME FG to circumvent these standards. The 5% threshold was created to avoid regional reliability impacts from constraints that should be managed with local procedures. NAESB standards should not be changed due to hypothetical situations.

21

Topic: What about a hypothetical situation

Questions & Discussion

22

10/6/2014

1

Project 2014-03Revisions to the TOP/IRO Reliability Standards

3rd Technical Conference and Second Posting WebinarAugust 12, 2014


• Introductions and Logistics

• NERC Antitrust Compliance Guidelines and Public Meeting Announcement

• SDT Roster

• Project History and Schedule

• Conference Objectives

• Project Inputs

• Second Posting Details

Definitions

IRO and TOP Standards

Data Retention, VRFs, and VSLs

SOL Exceedance Whitepaper

RSAWs

• Questions and Answers

Agenda

Presentation 4

10/6/2014

2


NERC Antitrust Compliance Guidelines and Public Announcement

• It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between or among competitors regarding prices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that unreasonably restrains competition. It is the responsibility of every NERC participant and employee who may in any way affect NERC’s compliance with the antitrust laws to carry out this commitment.

• Participants are reminded that this meeting is public. Notice of the meeting was posted on the NERC website and widely distributed. The notice included the number for dial‐in participation. Participants should keep in mind that the audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders.


SDT Roster

Dave Souder, PJM, Chair

Andy Pankratz, FPL, Vice Chair

David Bueche, Center Point

Jim Case, Entergy

Allen Klassen, Westar

Bruce Larsen, WE Energy

Jason Marshall, ACES

Bert Peters, APS

Robert Rhodes, SPP

Kyle Russell, IESO

Eric Senkowicz, FRCC

Kevin Sherd, MISO

10/6/2014

3


Project History and Schedule

• April 16, 2013: Projects 2006‐06 and 2007‐03 submitted

• November 21, 2013: Both projects proposed for remand

• December 20, 2013: NERC asked FERC to postpone remand

• January 14, 2014: FERC agreed to postpone until January 31, 2015

• February 12, 2014: Project 2014‐03 started

• May 19, 2014 – July 2, 2014: First posting

• August 6, 2014 – September 19, 2014: Second Posting

• October 2014: Final ballot

• November 12, 2014: Presented to NERC Board

• Filed with FERC ASAP after Board approval


Conference Objectives

• First Technical Conference was mid‐continent (St. Louis); second Technical Conference was east coast (DC); third Technical Conference is west coast to give those who couldn’t travel east a chance for personal interface with SDT

• Present the changes in the second posting and explain the SDT’s reasons for the changes

• Or, explain why the SDT didn’t make certain changes

• Continue outreach and education

• If you have a group that you would like to make certain receives a presentation, let one of the SDT members know

10/6/2014

4


Project Inputs

• Projects 2006‐06 and 2007‐03

• SARs

• Directives and Issues

• FERC NOPR

• Independent Experts Report

• SW Outage Report

• Operating Committee Executive Committee Memo

• IRO Five Year Review

• Technical Conferences

• St. Louis

• Washington, DC

• First Posting Comments


Second Posting Details

Definitions:

• Added ‘applicable’ as qualifier to list of inputs to alleviate concerns over an entity not having an input that was listed and being found non‐compliant

• “The assessment shall reflect applicable inputs including …”

• Replaced ‘contracted’ with ‘third‐party’ to allow for greater flexibility in providing services and to alleviate concerns of smaller entities

• “… may be provided through internal systems or through contractedthird‐party services.”

10/6/2014

5


Second Posting Details (cont.)

Real‐time Assessment (RTA): An evaluation of system conditions using Real‐time data to assess existing (pre‐Contingency) and potential (post‐Contingency) operating conditions. The assessment shall reflect applicable inputs including, but not limited to: load, generation output levels, known Protection System and Special Protection System status or degradation, Transmission outages, generator outages, Interchange, Facility Ratings, and identified phase angle and equipment limitations. (Real‐time Assessment may be provided through internal systems or through third‐party services.)

Operational Planning Analysis (OPA): An evaluation of projected system conditions to assess anticipated (pre‐Contingency) and potential (post‐Contingency) conditions for next‐day operations. The evaluation shall reflect applicable inputs including, but not limited to, load forecasts; generation output levels; Interchange; known Protection System and Special Protection System status or degradation; Transmission outages; generator outages; Facility Ratings; and identified phase angle and equipment limitations. (Operational Planning Analysis may be provided through internal systems or through third‐party services.)



IRO‐001‐4

• Applicability – Deleted Transmission Service Provider

• The Functional Model does not provide for a Reliability Coordinator directing a Transmission Service Provider to act.

• Requirement R1 ‐ Operating Instruction vs. Reliability Directive

• Operating Instruction definition is inclusive of directive. Operating Instruction allows Reliability Coordinators to address or prevent situations that could lead to an Emergency. The Reliability Directive definition was never approved by FERC (see NOPR) and will eventually be withdrawn. The use of Operation Instruction is consistent with proposed COM‐002‐4. Therefore, the SDT did not make any changes concerning Operating Instruction.

10/6/2014

6



IRO‐001‐4 (cont.)

• Requirement R3 – Deleted “citing one of the reasons shown in Requirement R2” based on industry feedback

• R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider, and Distribution Provider shall inform its Reliability Coordinator of its inability to perform the Operating Instruction issued by its Reliability Coordinator In Requirement R12 citing on of the specific reasons shown in Requirement R2.



IRO‐002‐4

• Requirement R1 – deleted

• Voice communication was deemed redundant with proposed COM‐001‐2

• Requirement R5 (now R4) – deleted ‘and highly reliable’ from infrastructure as unmeasurable

• This is a duplication of an existing requirement and compliance efforts should remain the same as today

• R5 (R4). Each Reliability Coordinator shall have monitoring systems that provide information utilized by the Reliability Coordinator’s operating personnel, giving particular emphasis to alarm management and awareness systems, automated data transfers, and synchronized information systems, over a redundant and highly reliable infrastructure.

10/6/2014

7




• Requirement R2 (now R1) – revised wording from ‘data links’ to ‘data exchange facilities’ and re‐structured language to allow for exchange to only be with the Transmission Operator and/or Balancing Authority with those entities reaching down to other entities or directly from the Reliability Coordinator to all applicable entities as per real‐world practice

• Requirement is not duplicative of proposed IRO‐010‐2 as that standard is about data and this requirement is about facilities

• ‘Data exchange capability’ is more generic and flexible

• Method should reflect actual practice

• R2 (R1). Each Reliability Coordinator shall have data exchange capabilities with Balancing Authorities and Transmission Operators, and with other entities it deems necessary, for it to perform its Operational Planning Analyses, Real‐time Monitoring, and Real‐time Assessments.




• Requirement R4 (now R3) ‐ re‐structured for clarity

• List formed at beginning of requirement rather than at the end

• Sub‐100 kV data clarified – ‘identified as necessary’ added to relieve concerns over reaching for unnecessary data

• Clarified Reliability Coordinator role for System Operating Limits (SOLs)

• Special Protection System term retained – if the project on re‐defining terms receives approval, all applicable standards will be revised at that time

• R4 (R3). Each Reliability Coordinator shall monitor Facilities, the status of Special Protection Systems, and sub‐100 kV facilities identified as necessary by the Reliability Coordinator, within its Reliability Coordinator Area and neighboring Reliability Coordinator Areas to identify any System Operating Limit exceedances and to determine any Interconnection Reliability Operating Limit exceedances

within its Reliability Coordinator Area.

10/6/2014

8



IRO‐008‐2

• Requirement R2 (review plans) – deleted as redundant with Requirement R3

• Requirement R3 (now R2) requires a coordinated plan which can’t be achieved without having reviewed the plans

• Requirement R4 (now R3) – deleted ‘NERC registered’ as a qualifier for entities

• R3. Each Reliability Coordinator shall notify impacted NERC registered entities identified in the Operating Plan(s) cited in Requirement R23 as to their role in those plan(s).

• Requirement R7 (issue Operating Instructions) – deleted as Operating Instructions are already covered in proposed IRO‐001‐4




• Requirement R5 (now R4) – changed ‘performed a Real‐time Assessment’ to ‘ensure that a Real‐time Assessment is performed’

• Allows flexibility for situations where other entities may perform Real‐time Assessment under a “Loss of Control Center Functionality” scenario as defined within that entity’s Operating Plan.

• R4. Each Reliability Coordinator shall perform ensure that a Real‐time Assessment is performed at least once every 30 minutes.

10/6/2014

9



IRO‐010‐2

• Applicability – deleted Planning Coordinator and Transmission Planner

• Data will be exchanged between a Reliability Coordinator and the Planning Coordinator/Transmission Planner but it doesn’t fit the data specification concept

• Effective Dates – changed the 10/12 month implementation to a 9/12 month implementation

• Better alignment with formal approval dates relieving possible overlap which would have erased the staggered implementation



IRO‐014‐3

• Requirement R1

• Added ‘and implement’ to ‘have Operating Processes’ to ensure actions are taken when needed

• Changed ‘other’ Reliability Coordinators to ‘adjacent’ Reliability Coordinators to avoid possibility of having to communicate with all other Reliability Coordinators

• R1. Each Reliability Coordinator shall have and implement Operating Procedures, Operating Processes, or Operating Plans, for activities that require notification or coordination of actions that may impact otheradjacent Reliability Coordinator Areas, to support Interconnection reliability.

• Deleted Part 1.5 as duplicative of proposed IRO‐001‐4, Requirement R1

• Reworded Part 1.6 to make it more generic as opposed to strictly being weekly conference calls

10/6/2014

10


Ssecond Posting Details (cont.)


• Deleted Part 1.5 as duplicative of proposed IRO‐001‐4, Requirement R1

• 1.5 Authority to act to prevent and mitigate system conditions which could adversely impact other Reliability Coordinator Areas.

• Reworded Part 1.6 to make it more generic as opposed to strictly being weekly conference calls

• 1.6 Provisions for weekly conference calls periodic communications to support reliable operations

• Requirement R3 – deleted as duplicative of Requirement R1

• R3. Each reliability Coordinator shall make notifications and exchange reliability‐related information with other impacted Reliability Coordinators in accordance with the Operating Procedures, Operating Processes, or Operating Plans identified in Requirement R1.




• Requirement R4 – deleted as duplicative of Requirement R1

• R4. Each Reliability Coordinator shall participate in agreed upon conference calls, at least weekly (per Requirement R1, Part 1.6) with other Reliability Coordinators within the same Interconnection.

• Requirement R5 (now R3) – added ‘expected or actual’ for consistency; clarified that it is only within the Reliability Coordinator Area

• R3. Each Reliability Coordinator, upon identification of an expected or actual Emergency in its Reliability Coordinator Area, shall notify other impacted Reliability Coordinators.

10/6/2014

11




• Requirement R7 (now R5) – clarified that it is only within the Reliability Coordinator Area and with ‘impacted’ Reliability

Coordinators

• R5. Each Reliability Coordinator that identified an Emergency in its Reliability Coordinator Area shall develop an action plan to resolve the Emergency during those instances where impacted Reliability Coordinators disagree on the

existence of an Emergency.

• Requirement R9 (now R7) – replaced ‘entity’ with ‘Reliability Coordinator’ and clarified that assistance can only be provided ‘if able’

• R7. Each Reliability Coordinator shall assist Reliability Coordinators, if requested and able, provided that the requesting entity Reliability Coordinator has implemented its emergency procedures, unless such actions cannot be physically be implemented or would violate safety, equipment, regulatory, or statutory requirements.



IRO‐017‐1

• Purpose – added timeframes of coordination for clarity

• To ensure that outages are properly coordinated in the Operations Planning time horizon and Near‐term Transmission Planning Horizon

• Described intent of Operations Planning time horizon

• The official definition of the Operations Planning Time Horizon is: “operating and resource plans from day‐ahead up to and including seasonal.” The SDT equates ‘seasonal’ as being up to one year out and that these requirements covers the period from day‐ahead to one year out

• Part 1.5 – deleted as duplicative of Part 1.3

• 1.5 Document and maintain the specifications for outage analysis during the operations planning horizon.

10/6/2014

12




• Requirement R4 – re‐structured to show that the process starts with the Planning Assessments created by the Planning Coordinator and Transmission Planner and then those Planning Assessments are reviewed and reconciled as needed with the Reliability Coordinator

• R4. Each Planning Coordinator and Transmission Planner shall jointly develop solutions with its respective Reliability Coordinator(s) for identified issues or conflicts with planned outages in its Planning Assessment for the Near‐Term Planning Horizon



TOP‐001‐3

• Requirement R1 – deleted ‘within its Transmission Operator Area’ as this may have inadvertently omitted some entities; clarified that reliability is the issue and not functions

• R1. Each Transmission Operator shall act, or direct others within its Transmission Operator Area to act by issuing Operating Instructions, to address ensure it’s the reliability functions within of its Transmission Operator Area.

• Requirement R2 – deleted ‘within its Balancing Authority Area’ as this may have inadvertently omitted some entities; clarified that reliability is the issue and not functions

10/6/2014

13



TOP‐001‐3 (cont.)

• Requirement R4 – deleted ‘citing one of the specified reasons shown in Requirement R3’ since the wording is administrative

• R4. Each Balancing Authority, Generator Operator, Distribution Provider, and Load‐Serving Entity shall inform its Transmission Operator of its inability to perform an Operating Instruction issued by its Transmission Operator in

Requirement R3 citing one of the specific reasons shown in Requirement R3.

• Requirement R7 – deleted Balancing Authority as non‐applicable; added ‘if able’ to provide assistance; changed ‘actions’ to ‘assistance’

for consistency

• R7. Each Transmission Operator and Balancing Authority shall assist otherTransmission Operators, if requested and able, provided that the requesting entity has implemented its emergency procedures, unless such actions assistancecannot be physically implemented or would violate safety, equipment, regulatory,

or statutory requirements.




• Requirement R9 – deleted ‘negatively’ as a qualifier to impacted and deleted ‘telecommunication’ as duplicative of proposed COM‐001‐2, Requirement R3

• R9. Each Balancing Authority and Transmission Operator shall notify its Reliability Coordinator and negatively impacted interconnected NERC registered entities of outages of telemetering and telecommunication equipment, control equipment, monitoring and assessment capabilities, and associated communication channels between the affected entities.

10/6/2014

14




• Requirement R10 ‐ re‐structured for clarity

• List formed at beginning of requirement rather than at the end

• Sub‐100 kV data clarified – ‘identified as necessary’ added to relieve concerns over reaching for unnecessary data

• Clarified that Transmission Operator is responsible for System Operating Limits (SOLs)

• Special Protection System term retained – if the project on re‐defining terms receives approval, all applicable standards will be revised at that time

• R10. Each Transmission Operator shall monitor Facilities, the status of Special Protection Systems, and sub‐100 kV facilities identified as necessary by the Transmission Operator, within its Transmission Operator Area and neighboring Transmission Operator Areas to determine any System Operating Limit (SOL) exceedances within its Transmission Operator Area.




• Requirement R13 – changed ‘performed a Real‐time Assessment’ to ‘ensure that a Real‐time Assessment is performed’

• R13. Each Transmission Operator shall ensure perform that a Real‐time Assessment is performed at least once every 30 minutes.

• Requirements R16 (and R17) – added ‘maintenance’ to ‘planned outages’ and added ‘telecommunication’ to list of items

• R16. Each Transmission Operator shall provide its System Operators with the authority to approve planned outages and maintenance of its ownmonitoring, telecommunication, and Real‐time Assessment capabilities.

10/6/2014

15




• Requirement R18 – deleted ‘Generator Operator’ from list as it does not get involved with limit determinations but simply receives Operating Instructions; changed ‘derived limits’ to ‘SOLs’ for clarity as to which limits are involved

• R18. Each Transmission Operator, and Balancing Authority, and Generator Operator shall always operate to the most limiting parameter in instances where there is a difference in derived limits SOLs.




• Requirements R19 and R20 – data exchange capabilities requirements for Transmission Operators and balancing Authorities similar to IRO requirement for Reliability Coordinator

• R19. Each Transmission Operator shall have data exchange capabilities with the entities that it has identified that it needs data from in order to maintain reliability in its Transmission Operator Area.

• R20. Each Balancing Authority shall have data exchange capabilities with the entities that it has identified that it needs data from in order to maintain reliability in its Balancing Authority Area.

10/6/2014

16



TOP‐002‐3

• Requirements R3 and R5 – deleted ‘NERC registered’ as qualifier to entities

• R3. Each Transmission Operator shall notify impacted NERC registered entities identified in the Operating Plan(s) cited in Requirement R2 as to their role in those plan(s).

• R5. Each Balancing Authority shall notify impacted NERC registered entities identified in the Operating Plan(s) cited in Requirement R4 as to their role in those plan(s).



TOP‐003‐3

• Applicability – deleted ‘Interchange Authority’ as that entity does not send data to the Transmission Operator or Balancing Authority

• Effective Date ‐ changed the 10/12 month implementation to a 9/12 month implementation

• Better alignment with formal approval dates relieving possible overlap which would have erased the staggered implementation

10/6/2014

17



Data Retention

• IRO‐008‐2 and TOP‐002‐4: changed data retention for analyses from six months to 90 calendar days to alleviate burden

• IRO‐008‐2 and TOP‐002‐4: changed data retention for voice recordings from three months to 90 calendar days for consistency

• IRO‐008‐2 and TOP‐001‐3: changed data retention from current calendar year and one previous calendar year to a rolling 30 day period for Real‐time Assessments to alleviate burden

• IRO‐014‐3: added missing item for Requirements R7 (now R5) and R9 (now R7)

• TOP‐001‐3: changed operator logs to 90 calendar days



VRFs

• IRO‐010‐2, Requirements R1 and R2: changed from Medium to Low for consistency with approved IRO‐010‐1a, Requirement R1 and proposed TOP‐003‐3, Requirement R1

• IRO‐017‐1, Requirements R1, R2, and R3: changed from Low to Medium to be consistent with approved IRO‐005‐3.1a, Requirement R6

10/6/2014

18



VSLs

• IRO‐002‐4, Requirement R2 (now R1) – changed from binary (severe) to incremental approach

• IRO‐008‐2, Requirement R5 (now R4) ‐ changed from binary (severe) to incremental approach

• IRO‐017‐1, Requirement R1 ‐ changed from binary (severe) to incremental approach

• TOP‐001‐3, Requirement R8: added an incremental approach to account for differential impacts on smaller entities

• TOP‐003‐3, Requirement R5: added incremental approach for consistency with approved IRO‐010‐1a, Requirement R1



VSLs (cont.)

• The SDT did not change the VSLs associated with Operating Instructions.

• These VSLs are proposed to be binary (severe).

• The requirement language is written on a single Operating Instruction basis.

• Therefore, the entity either does the action or it doesn’t.

10/6/2014

19



SOL Exceedance White Paper

• The Whitepaper is designed to provide the industry with a concise document that highlights existing NERC Standard Requirements and NERC Defined Terms, including examples, in an effort to promote clarity, consistency, and a common understanding of the concepts associated with establishing SOLs, exceeding SOLs, and implementing Operating Plans to prevent and mitigate SOL exceedance.



SOL Exceedance Whitepaper (cont.)

Technical basis:

• SOL Defined Term includes pre‐ and post‐Contingency Facility Ratings, Transient Stability Ratings, Voltage Stability Ratings, and System Voltage Limits.

Summarize approved FAC standards requirements for the clear determination of Facility Ratings and acceptable system performance criteria for the pre‐ and post‐

Contingency state.

o Approved FAC‐008‐3: Facility Ratings

- Requirement to develop , at a minimum, both Normal and Emergency Ratings.

o Approved FAC‐011‐2: System Operating Limits Methodology for the Operations Horizon

- Defines acceptable pre‐ and post‐Contingency BES performance and defines applicable Contingencies and study model

o Approved FAC‐014‐2: Establish and Communicate System Operating Limits

- SOLs are established consistent with SOL Methodology

- Facilitates Reliability Coordinator – Transmission Operator coordination

10/6/2014

20




Technical basis (cont.)

• Proposed TOP‐002‐4, Requirement R1 requires that each Transmission Operator have an Operational Planning Analysis to assess whether its planned operations for the next‐day within its Transmission Operator Area will exceed any of its SOLs.

• Proposed TOP‐002‐4, Requirement R2 requires that each Transmission Operator have an Operating Plan to address potential SOL exceedances identified as a result of its Operational Planning Analysis.

• Proposed TOP‐001‐3, Requirement R13 requires that a Transmission Operator ensures that a Real‐time Assessment is performed at least once every 30 minutes.

• Proposed TOP‐001‐3, Requirement R14 requires the Transmission Operator to initiate its Operating Plan(s) to mitigate SOL exceedances




Comment responses:

Clarity provided for SOL Examples.

Clarity provided to illustrate most limiting SOL.

Clarity provided for pre‐ vs. post‐Contingency load shed as per Operating Plan.

Modified to ensure whitepaper references NERC defined terms

10/6/2014

21


gridex program - nerc.com reliability subcommittee ors 20… · september 9, 2014 ... • rtca...

Documents