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RIC 2005 Presentation - C1 - Frank J. Koza - Grid Reliability
	ML052140118
Person / Time
Site:	Beaver Valley
Issue date:	03/08/2005
From:	Koza F; PJM Interconnection
To:	; Office of Nuclear Reactor Regulation
References
	Download: ML052140118 (19)
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Operating the PJM System NRC Regulatory Information Conference Session C1: Grid Reliability Frank J. Koza, General Manager Regional Operations of PJM Interconnection March 8, 2005

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May 1, 2004 - Commonwealth Edison

- Installation of a 500 MW pathway between ComEd and existing PJM control areas (= 2 control areas)

October 1, 2004 - AEP and Dayton Power and Light

- Removal of pathway and consolidation of the control areas to one control area

January 1, 2005 - Duquesne Light

- Inclusion of FE Beaver Valley as a capacity resource in PJM

Spring 2005 - Dominion

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Susequhanna 1&2

Oyster Creek

Salem 1&2/Hope Creek

Limerick 1&2

Peach Botton 2&3

Calvert Cliffs 1&2

Beaver Valley 1&2

DC Cook 1&2

Byron 1&2

Quad Cities 1&2

Braidwood 1&2

LaSalle 1&2

Surry 1&2

North Anna 1&2

TMI 2

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Inbound TVA

~500 MW Inbound VAP

~500 MW Outbound New York

~2000 MW Outbound Michigan

~2000 MW Inbound Cinergy

~500 MW Generally, there are large circulatory flows, coming into PJM from the south and west (e.g., Cinergy and TVA) and flowing north to New York and Michigan Outbound FE

~500 MW

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©2003 PJM PJM Confidential Control Performance--ABCs of ACE ACE = (NIA NIS) 10 (FA FS) IME Tie Error Component Total difference between actual and scheduled interchange summed across the metered boundaries of PJM Frequency Error Component Difference between actual frequency and scheduled frequency (normally 60 Hz)

For PJM, 1138 MW/0.1 Hz Bottom Line: PJM must keep its average ACE within +/- 258 MW for at least 90% of every 10 minute period for the month (NERC CPS-2 Control Performance Requirement)

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-1100

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100 200 300 400 500 600 700 800 900 1000 1100 ACE, Regulation Signal & Error Componets (MW)

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Net Schedule (MW)

Freq Error Component of ACE Tie Error Component of ACE CPS2 Violations RTO Regulation Signal PJM RTO ACE Net Schedule 04:00 04:10 04:20 04:30 04:40 04:50 05:00 05:10 05:20 05:30 05:40 05:50 06:00 06:10 06:20 06:30 06:40 06:50 07:00 07:10 07:20 07:30 07:40 07:50 08:00 Time (EDT)

MAN.REG ACE v L10 ACE Components, Jan 24, 2005 Cold morning pickup10,000 MW of CTs called on to meet load, only 5000 MW initially startothers are delayed starting = 8 CPS2 violations Late starting CTs hit the bus, forcing a reversing action

+L10

-L10 PJM Load grew by over 20,000 MW during this 4 hr period!

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When we needed them When we got them

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100 200 300 400 500 600 700 800 900 1000 1100 ACE, Regulation Signal & Error Componets (MW)

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500 1000 Net Schedule (MW)

Freq Error Component of ACE Tie Error Component of ACE CPS2 Violations RTO Regulation Signal PJM RTO ACE Net Schedule 16:00 16:10 16:20 16:30 16:40 16:50 17:00 17:10 17:20 17:30 17:40 17:50 18:00 18:10 18:20 18:30 18:40 18:50 19:00 19:10 19:20 19:30 19:40 19:50 20:00 Time (EDT)

MAN.REG ACE v L10 ACE Components, Jan 24, 2005 Serendipitous alignment of tie error and frequency error, effectively canceling each other

+L10

-L10 Only 2 CPS-2 Violations

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Created by the owners as a feature of PJM governance (PJM staff facilitates and provides administrative support)

Broad participation from the nuclear owners: AEP, AmerGen, Constellation, Dominion, Exelon, First Energy, PPL, and PSEG

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Cultural Differences

- Communications (Dont speak the same language)

- Have differing regulatory accountabilities (FERC vs. NRC vs. State PUCs)

- Market role (Code of Conduct issues)

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©2003 PJM PJM Confidential PJM Response to Cultural Differences Issue Nuclear Communications Protocol (PJM Manual M-1, Attachment B) http://www.pjm.com/contributions/pjm-manuals/pdf/m01v08.pdf Features:

- Nuclear Safety/ Grid Reliability Philosophies

- Roles and Responsibilities

- Key Terms Defined

- Event Communications

- Regulatory Background Information

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©2003 PJM PJM Confidential Example Definition from the Nuclear Communications Protocol KEY TRANSMISSION TERMS First Contingency Violation The transmission system is operated so that the single loss of any facility (line, generator, etc.) will not result in violation of any operating limit. The single loss is called the first contingency.

The transmission operators have software that simulates the first contingency individually for a number of facilities on the system.

Implication: The operators are required to correct any first contingency violation that will violate the emergency ratings on any facility within a period of time (normally within 30 minutes). If the operators ask the nuclear plant to take action as the result of the first contingency violation, the action should be implemented unless the action will jeopardize nuclear safety, personnel safety, or equipment protection.

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Post-contingency Voltage Stability

- NPPs generally have more restrictive voltage limits than the grid

- In an accident scenario, will the safety systems work if needed?

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©2003 PJM PJM Confidential PJM Response to Voltage Concerns Notification and Mitigation Protocols for Nuclear Plant Voltage Limits (PJM Manual M-3, Section 3, page 36) http://www.pjm.com/contributions/pjm-manuals/pdf/m03v14.pdf Regarding Code of Conduct issues:

If PJM operators observe voltage violations or anticipate voltage violations (pre or post-contingency) at any nuclear stations; PJM operators are permitted to provide the nuclear plant with the actual voltage at that location, the post-contingency voltage at that location (if appropriate) and limiting contingency causing the violation.

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Outage Coordination

- NPP perspective: Getting the transmission owner to perform maintenance when the NPP is in an outage to mitigate NPP risk

- Transmission perspective: We dont schedule maintenance the way they do.

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- Strict advanced notification requirements

- Multiple step analysis process to ensure reliability is maintained

- Wide dissemination of outage information

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©2003 PJM PJM Confidential Special Consideration for Nuclear Plants The Nuclear Generating Stations coordinate the scheduling of a Unit Breaker outage and internal plant equipment outages and testing to minimize station risk.

Adherence to outage schedule and duration is critical to the plant during these evolutions. Emergent plant or transmission system conditions may require schedule adjustments, which should be minimized. Any change to the outage schedule that impacts the Unit Breakers shall be communicated to the nuclear generator operator.

The following Nuclear Generating Stations have transmission system connections that can impact Nuclear Station Safety Systems:

Peach Bottom:

Limerick:

Unit 2: CB 215 Unit 1: CB 535 CB 225 CB 635 Unit 3: CB 15 Unit 2: CB 235 CB 65 CB 335 Salem:

Oyster Creek:

Unit 1: 5 - 6 B.S. 10X GD1 2 - 6 B.S. 11X GC1 Unit 2: 9 - 10 B.S. 30X 1 - 9 B.S. 32X Hope Creek:

Calvert Cliffs:

BS 6 - 5 50X Unit 1: 552 - 22 BS 2 - 6 52X 552 - 23 Unit 2: 552 - 61 552 - 63

ML052140118

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