Ten years ago today, on Aug. 14, 2003, a fault on First Energy‘s (NYSE:FE) system triggered a massive blackout that stretched across the Midwest and Northeast U.S. and into Ontario, Canada. The event affected 50 million people and nearly 62 GW of load – and galvanized the electric industry into action.
A task force formed by the U.S. and Canadian governments released an analysis of the blackout in 2004 and made 46 recommendations. First and foremost among them was to make NERC reliability standards mandatory and enforceable, with penalties for noncompliance.
“Unfortunately, it took the 2003 blackout for Congress to recognize the obvious, which is that voluntary standards don’t work on the highway of electricity; there’s got to be traffic cops,” FERC Commissioner Philip Moeller told TransmissionHub.
In response to the report’s recommendations, utilities and regional transmission organizations across the country ramped up their training programs for system operators, developed better vegetation management programs and adopted technologies that significantly enhance the ability to see how the grid is operating.
The area in which the industry has made the most progress is vegetation management, several sources said. The fault on First Energy’s system was caused by contact between a conductor and a tree.
“[That] caused the industry to look at how we take care of tree trimming,” Mike Bryson, executive director of system operations for PJM Interconnection, told TransmissionHub. “That may be probably the most thorough effect of the new mandatory standards.”
The maturity of utilities’ vegetation management programs has greatly improved from what it was 10 years ago, Scott Moore, vice president of transmission engineering and project services for American Electric Power (NYSE:AEP), told TransmissionHub. “You don’t hear of a ‘grow-in’ outage anymore; there may be trees outside the right-of-way that blow in and cause an outage but you don’t hear of grow-ins like we had in 2003,” he said.
The Energy Policy Act of 2005 made NERC reliability standards mandatory and authorized FERC to enforce them.
“I think it’s fair to say that since the beginning of us having the authority under the 2005 Act, that vegetation management has been probably one of the top three categories of things we spend time and attention on,” Moeller said.
The commission may levy fines of up to $1m per day per violation. “That gets people’s attention,” Moeller said.
Training programs have been more vigorous, with utilities and control rooms using simulators and requiring system operators to spend, in some cases, several weeks a year managing simulated emergency situations.
The 2004 outage report found that a lack of adequate training of system operators was a major contributor to the blackout.
“One of the things we do now is more simulations,” Bryson said. “We can take a shift of operators and move them into the simulators. We can throw a lot of things at them that you wouldn’t want to do in the control room. Every single week of the year, we have one shift that goes into the simulator, so we’re constantly rotating the six shifts that I have through the simulator.”
In addition to RTOs, individual utilities also run simulations. AEP, for example, has a simulator that it trains dispatchers on, in addition to a new control center, Moore said.
The Midcontinent ISO (MISO) has a dedicated training week every six weeks for its operators, including dispatcher training simulations, David Zwergel, senior director, regional operations for MISO, told TransmissionHub.
The technology that every source said was essential to grid reliability was synchrophasors, or phasor measurement units (PMUs). PMUs take measurements at high speeds, and each measurement is time-stamped. This provides entities, including utilities, to synchronize their different synchrophasors, giving them a more detailed look at the system.
The U.S. Department of Energy (DOE) has deployed 850 synchrophasors on the transmission system, Patricia Hoffman, assistant secretary for the Office of Electricity Delivery and Energy Reliability at the DOE, told TransmissionHub.
“At the transmission level, that’s the most important investment we’re doing,” she said.
Synchrophasors transmit data up to 30 to 60 times per second, giving a better real-time view of what is happening on the grid than SCADA (supervisory control and data acquisition) systems, which transmit data every 2 to 30 seconds, Bryson said.
In the pre-phasor world, a unit could trip offline and operators would see that event within a couple of seconds to a minute, spend a minute determining what the unit is and the appropriate actions to take, from deploying reserves to moving regulation or contingency reserves to respond to it. Those measures would remain in place until the system is stable and then operators would return it to normal economic dispatch, Bryson said.
“Given that timeline, the concept of synchrophasors is that you may see some of those indications, because of phase angle differences, with the unit prior to the unit actually tripping,” he said. “Given that kind of correlation, you have the ability to raise generation economically in a more orderly fashion.”
Synchrophasors also offer better after-the-fact analysis.
“It took NERC utilizing the synchrophasor information about a week to analyze the sequence of events that happened in the Southwest blackout in 2011,” Hoffman said. “When we did the 2003 blackout [analysis], it took us over six weeks to analyze the sequence of events, so it provides a great forensic capability in analyzing what’s happening on the system.”
Synchrophasor use, however, is still in the pilot phase, and production-grade deployment and utilization is one to five years off, according to various estimates.
The other advancement that has been made in the last decade is the use of visualization tools. These process data and generate a color map, not unlike meteorological maps that show the intensity of temperatures across the country, that indicates where a low-voltage problem might occur.
Ten years ago, alarms at different substations would alert an operator to a low-voltage event, but the operator would have to know the system very well to know that the substations happened to be in the same area.
With the visualization tools, “The operator can take that graphical information and can understand it much quicker than going through line after line of alarms and put it together in his head,” Moore said.
Regions and companies are also sharing real-time data with their neighbors. AEP models its system, and gets the models of its neighboring systems, incorporates it, and is able to get a widespread view of the system, he said.
“Now we have a state estimator contingency analysis, so we’re monitoring much of the Eastern Interconnection,” Zwergel said. “We can see everything. We have literally thousands of branches [on which] we can see the flows across a transmission line, [and] a few hundred thousand data points coming in every so many seconds. We didn’t have that available in 2003.”
For all these advancements, though, the electric grid, which didn’t see investment for decades, is playing catch-up in many ways.
“It’s been a decade since most Americans learned, through the Northeast blackout, that deferred maintenance on a small facility attached to our national grid could cause a huge part of our U.S. population to be without power for days,” Lynn Greene, CEO of Lucky Transmission, told TransmissionHuh. “Modernizing our electric grids, which are also the foundation of the Internet, needs to be a national priority.”
Click here to read Part II on the next generation of reliability challenges