Squeezing plant outage duration by days or even weeks can save the industry billions of dollars in lost running time. The San Onofre outage is just the most visible example of what’s at stake for...
Reliability Monitoring: The High-Tech Eye In the Sky
How reliability performance monitoring and standards compliance will be achieved in real time.
The DOE-NERC Collaboration
Shortly after the formation of CERTS, members participated in the energy secretary’s Power Outage Study Team to investigate the blackouts and grid disturbances of the summer of 1999. During that investigation, one of the key events—extended periods of low frequency in the Eastern Interconnection followed by rolling blackouts—dramatically demonstrated the need for new wide-area tools to detect violations of reliability rules in real time.
During the July 1999 Eastern Interconnection low-frequency events, generation resources were inadequate to meet electricity demand, which jeopardized grid reliability and ultimately led to rolling blackouts in the middle South. NERC operating policies require that each operator balance generation with demand in its control area within 10 minutes, including dropping loads if necessary, to avoid a cascading event that could jeopardize the reliability of the entire interconnection. Members of the relevant NERC operating committees investigated the July 1999 events using established procedures, which required time-consuming manual investigations involving compilation and review of operating records and comparing scheduled transactions with actual flows.
Because of the time required for this manual review, it was not until five months later, December 1999, that the East Central Area Reliability Coordination Agreement issued a strongly worded reprimand to a Midwest utility, citing blatant disregard for reliability rules and threatening to revoke the utility’s authority to operate as a control area. The investigation had found at least six hours during which the utility had failed to meet its obligations by more than 1,000 MW. Those actions had disturbed the interconnection’s delicate supply-and-demand balance and created conditions that led to rolling blackouts affecting more than half a million customers in three states. Interestingly, the spot price of electricity in the Midwest during that period was routinely in the thousands of dollars per megawatt-hour, with a high of $5,000/MWh. By “leaning on the ties” and not meeting its obligations, the utility was avoiding millions of dollars per hour in spot-market purchases.
This event and its aftermath highlighted both the need for mandatory reliability rules and the need for new tools to replace manual review of records to monitor compliance with the rules. While Congress worked to pass legislation making the rules mandatory, DOE and NERC, through CERTS, began collaborating to develop and pilot new tools to monitor compliance in real time.
Development of a wide-area, real-time Area Control Error (ACE)-Frequency monitoring system was one of the first CERTS successes. 2 The new system provides reliability authorities with real-time situational awareness of grid frequency performance and the diagnostic tools to determine the nature and origin of problems. Use of the new system ensures that the review process, which in 1999 took five months, can now be accomplished in minutes.
CERTS, supported by NERC staff, developed the ACE-Frequency Monitoring System with funding from DOE and under the guidance of the NERC Resources Subcommittee, which oversees development of metrics and monitoring of compliance with NERC’s resource adequacy rules. The ACE-Frequency system was field-tested in 2002 and today is in use by all 17 NERC reliability authorities and several control area operators.
The ACE-Frequency system