Inadequate planning coupled with a lack of system operability and awareness of system operating conditions are being cited as the primary reasons for the Sept. 8, 2011 blackout that left 2.7 million customers without power in Southern California, Arizona and Baja California.
Those are the primary conclusions of a joint report by FERC and NERC, issued May 1 after an eight-month inquiry. The inquiry into the events of Sept. 8 was initiated to determine how the blackout occurred and to make recommendations to avoid similar situations in the future.
NERC officials called the blackout one of the more complex electrical events in North America since the 2003 Northeast blackout.
“The details of the event underscore just how complex and inter-dependent our North American electric systems are,” said NERC senior vice president Dave Nevius. “Transmission operators, balancing authorities, and reliability coordinators all must work together to effectively manage this complex system.”
While early reports blamed the event on Arizona Public Service’s (APS) Hassayampa-North Gila 500-kV line tripping during maintenance work, the report says the line loss itself was exacerbated because the region’s bulk electric system was not being operated to an “N-1” contingency standard.
As a result, the loss of the line “resulted in instability, uncontrolled separation, and cascading outages.” according to Heather Polzin, FERC’s team lead for the study. Those factors triggered a sequence of more than 100 notable events that occurred in less than 11 minutes and resulted in the cascading blackout.
According to the report, the loss of the APS line caused the progressive loading of the five 230-kV tie lines from Southern California Edison (SCE) north of San Diego that form Path 44, to exceed Path 44’s 8,000-amp capacity. That overload triggered the San Onofre nuclear generating station separation scheme, which blacked out San Diego, the Imperial Irrigation District (IID), Mexico’s Comisión Federal de Electricidad’s (CFE) Baja California control area, and Yuma, Ariz., in less than 30 seconds.
“Even though protection systems operated as designed, they made matters worse, which calls into question whether they were properly designed, studied, or coordinated,” Polzin said.
The events of Sept. 8 exposed grid operators’ lack of adequate real-time situational awareness of conditions throughout the Western Interconnection. “Entities other than [APS] generally weren’t aware that the line had tripped in real-time, even though its loss affected their system,” Polzin continued.
According to the report, more effective review and use of information would have helped operators avoid the event.
“For example, several transmission operators did not know that over 600 MW of generation in the key location was out for maintenance, and did not reflect this in their planning studies,” Polzin said.
If operators had reviewed and heeded real time contingency analysis results prior to the loss of the APS line, they could have taken corrective actions. Actions such as dispatching additional generation or shedding load could have prevented a cascading outage, according to the report.
The 153-page report includes 27 recommendations intended to help industry operators prevent similar outages in the future.
Recommendations include transmission operators and balancing authorities improve their next-day, seasonal, and near- and long-term planning procedures. Operators should also consider the effect of external operations on their own systems, as well as how operation of transmission facilities under 100-kV can affect the reliability of the bulk power system.
The report also recommends that bulk power system operators improve their situational awareness through improved communication, data sharing and the use of real-time tools.
APS is a subsidiary of Pinnacle West Capital Corp. (NYSE: PNW).
SCE is a subsidiary of Edison International (NYSE:EIX).