Agenda
Operating Committee
March 21, 2007 1 p.m. to 5 p.m.
March 22, 2007 8 a.m. to noon
Westin Long Beach
333 East Ocean Boulevard
Long Beach, California
562-436-3000
Item / Leader / Action- Administration
- Quorum
- Procedures
- New Members
- Introductions
- Agenda
- Consent Agenda
- For Your Information
- Balance Resources and Demand Standards, BAL-007 through BAL-011
- Reliability Criteria and System Limits Concepts
- Definition of “Adequate Level of Reliability”
- Lessons Learned
- 11/4/06 Europe blackout and other studies
- Hydro One Capacitor Bank Failure
- Reliability Readiness Evaluation and Improvement Program
- Electing the OC Members
- Real-time Tools Best Practices
- Midwest ISO Balancing Authority
- Market Flow Field Test
- Reliability Coordination Plan Approval Process
- Frequency Monitoring
- E-tag Version 1.8
- Next Meetings
Item 1.Administration
Item 1.aAnnouncement of Quorum
The secretary will announce whether a quorum (two-thirds of the voting members) is in place. NOTE: The committee cannot conduct business without a quorum. Please be prepared to stay for the entire meeting.
Item 1.bProcedures
The NERC Antitrust Compliance Guidelines, Organization and Procedures Manual, and a summary of Parliamentary Procedures are attached for reference. The secretary will answer questions regarding these procedures.
Attachments
- Antitrust Guidelines
- Parliamentary Procedures
- Organization and Procedures Manual for the NERC Standing Committees
Action – Waiver of “Ten-Day” Rule
The chairman will waive the rule requiring a ten-day posting before an item can be brought to the committee for consideration. (See text at right.) The committee members are free to make any motions they desire.
Item 1.cIntroduction of Members and Guests
The chairman will ask the committee members and guests to introduce themselves.
Attachment
Operating Committee roster
Item 1.dApproval of Agenda
Action
Approve meeting agenda.
Background
The chairman will review the agenda, ask for amendments, and then approval.
Item 2.Consent Agenda
The consent agenda allows the Operating Committee to approve routine items that would not normally need discussion. Any OC member may ask the chairman to remove an item from the consent agenda for formal discussion and action.
Action
Approve the attached documents.
Attachment
- Minutes of December 67, 2006 Operating Committee meeting.
Item 3.For Your Information
The committee doesn’t need to take any action on these items. They are presented here for information and discussion as the members may wish.
Item 3.aBalance Resources and Demand Standards,BAL-007 through BAL-011
- February 15–March 16, 2007: 30 Day Pre-ballot Review
- March 19–30, 2007: Ballot Window
More information is attached.
Item 4.Reliability Criteria and System Limits Concepts
Action
Discussion.
We are providing additional time here for the committee to discuss the reliability and system limits concepts, which was the main topic of the joint meeting that morning.
It’s important for the committee to understand the reliability criteria concepts, how we propose to define System Operating Limit and Interconnection Reliability Operating Limit, and how all this ties into the definition of “adequate level of reliability.” (Item 5).
Item 5.Definition of “Adequate Level of Reliability”
Action
Discussion.
Attachment
Draft of NERC Compliance Filing of the North American Electric Reliability Corporation in Response to January 18, 2007 Order, Item 16.
Background
The attachment (still a “working draft”) explains that the NERC Operating Committee and Planning Committee will lead the effort to define an “Adequate Level of Reliability.”
Thoughts from the OC secretary
The definition of an adequate level of reliability is neither a yardstick nor metric per se. Rather, it is based on the ability to meet NERC’s planning and operating reliability criteria. These criteria are, in the most general terms, that we plan and operate the interconnections so that credible contingencies result in acceptable performance.
While simply stated, these criteria are based on at least six concepts, all of which need the Operating Committee’s and Planning Committee’s thoughts, ideas, and discussion. These concepts are:
- Acceptable risk the chance an event will jeopardize reliability, and the consequences if it does
- Credible contingencies the events that we learn from experience are more or less likely to happen
- Acceptable performance how we want the interconnection to perform after a credible contingency
- Boundary conditions what was studied in the planning and operations planning time frames
- System operating limits where the system operator must be in real time to ensure that credible contingences result in acceptable performance
- Time frames how boundary conditions and limits are calculated in the planning, operations planning, and real-time operations periods
The Operating Limit Definition Task Force is working on these concepts, and discussed some of these at the Operating Committee and Planning Committee December 2006 joint meeting. We will cover more of them in considerable depth at this joint meeting.
Finally, when you read the Planning Committee’s agenda, you will find an item called the “Adequate Bulk Power System Planning Committee Adequacy Sub-Team.” This is a project the Planning Committee started several months ago, before the FERC asked NERC to define “adequate level of reliability.” The topics and issues the PC’s sub-team has raised are very similar to the reliability criteria concepts listed above.
Item 6.Lessons Learned
Discussion items.
Item 6.aNovember 4, 2006 Europe blackout and other studies
This item is closely tied to Item 4, “Reliability Criteria and System Limits Concepts.”
From NERC Newsletter, February, 2007.
The Union for the Coordination of Transmission of Electricity (UCTE), an association of Transmission System Operators (TSOs) in continental Europe, issued its Final Report, entitled “System Disturbance on 4 November 2006.” On that date, a severe frequency drop in the Western part of continental Europe’s grid interrupted the electricity supply for more than 15 million households. The disturbance, resulting from the tripping of a number of high voltage lines in northern Germany, triggering a split of the system into 3 areas. The two under-frequency areas (West and South-East) had sufficient generation reserves and load shedding for the system to be restored within 20 minutes. In the over-frequency area (North-East) insufficient control of generation on the distribution network (dispersed generation, mainly wind and combined-heat-and-power) complicated the process of restoration, which was completed 38 minutes.
UCTE’s press release, presentation and report provide a detailed description of the sequence of events, an analysis of main causes and critical factors and the formulation of precise recommendations (highlighted items relate to reliability concepts and system limits):
Main causes
- Nonfulfillment of the n-1 reliability criterion
- Insufficient inter-TSO coordination
Critical factors
- TSOs’ did not have access to real-time data of the generating units connected to the distribution grids (mainly wind and combined-heat-and-power).
- Limited range of actions available to dispatchers for handling grid congestions
- TSO/Distribution Service Operators (DSO) lacked operational coordination for operations and restoration plans
- TSOs lacked coordination with other TSOs during resynchronization procedures
- Training of dispatchers for inter-control area events
Recommendations
- Review the application of the n-1 criterion in the rules of the UCTE Operation Handbook.
- Extend the rules on emergency operations with a “Master Plan” defining principles of operation and TSOs’ responsibilities to manage UCTE-wide or regional disturbances.
- Develop standard criteria for a regional and an interregional TSO coordination aimed at improving the regional reliability management (from planning to real time).
- Provide an information platform so TSOs can observe, in real time, the state of the UCTE system and enable quick reaction during large disturbances.
- Adapt the regulatory or legal framework regarding control over generation output, requirements to be fulfilled by generators connected to the distribution grid, schedules and schedule changes, and access to online data of generators connected to the distribution grid.
UCTE will issue a second report at the end of 2007 about the implementation of these recommendations.
Item 6.bHydro One Capacitor Bank Failure
Ajay Garg from Hydro One will discuss the January 30, 2007 capacitor bank failure at Richview Transformer Station, located just outside Toronto. (See Hydro One press release)
This event is a notable occurrence for a number of reasons:
- It is the first catastrophic failure of an HV capacitor bank in the Hydro One system. (The initiating cause of the phase-to-phase fault remains unknown.)
- Both primary and backup capacitor bank breakers (connected in series) failed to clear during the fault. Bus fault protection eventually cleared the fault 287 ms after inception.
- The delayed clearance resulted in prolonged voltage dips across the southern part of the province and caused 1,700 MW of voltage-sensitive load to be “shaken off.”
- Subsequent examination and modeling of the event revealed a previously unknown (to Hydro One) risk in capacitor bank installations that employ a series reactor. Hydro One’s investigation identified that, although the contacts of both breakers opened, the arc re-ignited due to excessive RRRV (Rate of Rise of Recovery Voltage). This effect was caused by fault current flowing through a series reactor located electrically adjacent to the faulted capacitor. (See explanation at right.)
In light of the findings and the potential consequences of such a fault, Hydro One would like to raise the awareness of other utilities to this risk (which may not be widely known).
Item 7.Reliability Readiness Evaluation and Improvement Program
Action
Approve addition of the Reliability Readiness Evaluation and Improvement Program to the Operating Committee’s charter.
Once the Operating Committee has approved this change, we will bring the committee’s charter to the NERC Board of Trustees for approval. NERC will also need to revise its Rules of Procedure, Appendix 7, as follows:
Attachments
Operating Committee Charter Version 2
NERC Rules of Procedure, Section 700 Reliability Readiness Evaluation and Improvement.
NERC Rules of Procedure Appendix 7, “Reliability Readiness Evaluation and Improvement Program Procedure.”
Background
Reliability Readiness Evaluation and Improvement Program director Rich Schneider, along with former program director Gerry Adamski (who now heads NERC’s standards program), will lead this discussion.
Item 8.Electing the Operating Committee Members
Action
Approve member election process.
We will begin this discussion at the joint meeting.
Attachment
“Procedure for Electing Members to the Operating Committee and Planning Committee” (Will be sent separately).
Background
Section 3 of the Operating Committee charter explains the membership selection procedure (see excerpt at right).
The charter allows each sector to establish its own selection process, similar to the Member Representatives Committee. But we (NERC staff) ended up managing the nomination and balloting process for all the sectors, which worked well. In fact, it’s a very good way to ensure we don’t have one organization providing more than one representative. And it keeps the process open and inclusive.
We suggest doing the same for the Operating Committee and Planning Committee. This involves:
- Announcing the nomination periods and providing nomination forms.
- Posting nominations on the NERC Web site.
- Announcing balloting periods and providing balloting forms.
- Posting the ballot results on the NERC Web site.
All of these procedures and forms are already set up.
John Seelke and Don Benjamin are working on a procedures document similar to the “Plan for Creating the Member Representatives Committee.” It’s not ready yet, but we will send it to the OC and PC once we have a working plan.
Item 9.Real-time Tools Best Practices
Action
Discussion.
Jack Kerr, chairman of the Real-time Tools Best Practices Task Force, will providea summary of the task force’s findings, conclusions, andrecommendations for reliability standards and operating guides development.
This will be a rather in-depth presentation.
Report status
The task force is working on its final report (about 400 pages!). We will forward the executive summary to the Operating Committee as soon as it is ready.
Background
Note: The following are excerpts from the 2003 blackout final report and NERC recommendations. The “task force” referenced below is the U.S.-Canada Power System Outage Task Force.
U.S.-Canada Power System Outage Task Force Recommendation 22 — Evaluate and adopt better real-time tools for operation and reliability coordination
NERC’s requirements of February 10, 2004 direct its Operating Committee to evaluate within one year the real-time operating tools necessary for reliability operation and reliability coordination, including backup capabilities. The committee’s report is to address both minimum acceptable capabilities for critical reliability functions and a guide to best practices. The task force supports these requirements strongly. It recommends that NERC require the committee to:
- Give particular attention in its report to the development of guidance to control areas and reliability coordinators on the use of automated wide-area situation visualization display systems and the integrity of data used in those systems.
- Prepare its report in consultation with FERC, the appropriate authorities in Canada, DOE, and the regional reliability councils. The report should also describe actions by FERC and Canadian government agencies to establish minimum functional requirements for control area operators and reliability coordinators.
The task force also recommends that FERC, DHS, and appropriate authorities in Canada should require annual independent testing and certification of industry EMS and SCADA systems to ensure that they meet the minimum requirements envisioned in Recommendation 3.
Additional Background Material from the U.S.-Canada Power System Outage Task Force Report
A principal cause of the August 14 blackout was a lack of situational awareness, which was in turn the result of inadequate reliability tools and backup capabilities. In addition, the failure of FE’s control computers and alarm system contributed directly to the lack of situational awareness. Likewise, MISO’s incomplete tool set and the failure to supply its state estimator with correct system data on August 14 contributed to the lack of situational awareness. The need for improved visualization capabilities over a wide geographic area has been a recurrent theme in blackout investigations. Some wide-area tools to aid situational awareness (e.g., real-time phasor measurement systems) have been tested in some regions but are not yet in general use. Improvements in this area will require significant new investments involving existing or emerging technologies.
The investigation of the August 14 blackout revealed that there has been no consistent means across the Eastern Interconnection to provide an understanding of the status of the power grid outside of a control area. Improved visibility of the status of the grid beyond an operator’s own area of control would aid the operator in making adjustments in its operations to mitigate potential problems. The expanded view advocated above would also enable facilities to be more proactive in operations and contingency planning.
Annual testing and certification by independent, qualified parties is needed because EMS and SCADA systems are the nerve centers of bulk electric networks. Ensuring that these systems are functioning properly is critical to sound and reliable operation of the networks.
NERC Recommendation 10 — Establish Guideline for Real-Time Operating Tools
The August 14 blackout was caused by a lack of situational awareness that was in turn the result of inadequate reliability tools and backup capabilities. Additionally, the failure of FE’s control computers and alarm system contributed directly to the lack of situational awareness. Likewise, MISO’s incomplete tool set and the failure of its state estimator to work effectively on August 14 contributed to the lack of situational awareness.
Recommendation 10: The Operating Committee shall within one year evaluate the real-time operating tools necessary for reliable operation and reliability coordination, including backup capabilities. The Operating Committee is directed to report both minimum acceptable capabilities for critical reliability functions and a guide of best practices.
This evaluation should include consideration of the following:
- Modeling requirements, such as model size and fidelity, real and reactive load modeling, sensitivity analyses, accuracy analyses, validation, measurement, observability, update procedures, and procedures for the timely exchange of modeling data.
- State estimation requirements, such as periodicity of execution, monitoring external facilities, solution quality, topology error and measurement error detection, failure rates including times between failures, presentation of solution results including alarms, and troubleshooting procedures.
- Real-time contingency analysis requirements, such as contingency definition, periodicity of execution, monitoring external facilities, solution quality, post-contingency automatic actions, failure rates including mean/maximum times between failures, reporting of results, presentation of solution results including alarms, and troubleshooting procedures including procedures for investigating unsolvable contingencies.
Item 10.Midwest ISO Balancing Authority
Action
Endorse the Operating Reliability Subcommittee’s conclusions regarding the creation of the MISO balancing area.