“Phasors” have nothing to do with STAR TREK; they’re the way of the future for monitoring the nation’s power grid.

On August 14, 2003, a cascading power failure left 50 million people in the northeastern United States and eastern Canada in the dark. It was the largest blackout in American history and prompted calls for better ways to monitor the nation’s electrical power system.

Now new measurements, called phasors, provide simultaneous measurements of voltage, current and frequency across a wide area of the grid. Phasors provide operators with a faster means to take the pulse of the nation’s electrical power grid. Phasors describe the differences in timing between the crests of the waveforms that characterize electrical power as it travels through the lines.

“If we had phasors in place then, we would have been able to see very clearly at least 30 minutes before that event that we were in trouble,” said Stan Johnson, a manager at the North American Electric Reliability Corp. (NERC), which is responsible for situation awareness and security of electrical infrastructure. NERC sets standards for how electrical grids are managed and ensures that grid operators comply.

Thirty minutes would have been enough time to take corrective action. “We probably would have wound up shutting the lights off in the Cleveland, Ohio, area, but at least [the blackout] would not have steamrolled all the way across the Northeast,” Johnson said.

Power once came from relatively local sources. Now that new markets have opened, electricity from inexpensive or renewable sources that can be located in remote areas can be transmitted over long distances to densely populated regions with high power demands. As a result, Johnson contends, bulk power systems are operating much closer to their limits.

NERC is working with the U.S. Department of Energy (DOE) to implement the use of phasor measurements throughout the hundreds of thousands of lines that supply most of the country with power. “Ideally those measures hold steady,” said electrical engineer Jeff Dagle of Pacific Northwest National Laboratory, who supports DOE’s transmission reliability program. Rapid changes in the phasor measurements signal instabilities in the system.

“What you’d do is cut schedules,” Dagle said. Because considerable power is sent around the grid for economic convenience, the cheapest resource, which might be further away than an expensive resource, is most likely to be tapped. “If you know that the grid can handle it, then there’s no problem,” he said. “But when you either know or suspect that the grid is going to have problems, you can fire up generation that’s closer to the load and alleviate some of that stress.”

Three separate systems transfer power in the United States. The Eastern Interconnection serves most of the Midwest, the eastern seaboard and parts of Canada. Texas has its own system, and the Western Interconnection serves the states from the Rocky Mountains west and parts of Canada and Mexico.

The western grid was the first to implement phasor measurements as a way to manage loads on the long transmission lines required by sparse populations and remote power sources. “It’s like weights and springs,” Dagle said. “Each generating plant might be a weight, and each transmission line is like a spring. In a steady state, everything would be nice and stable, but if there’s a change, it’ll bounce or oscillate.”

A large part of the western grid failed on August 10, 1996, as a result of this phenomenon. Hot weather in California, combined with abundant water for hydropower in the northwest, meant that “they were pushing a lot of power through a constrained transmission infrastructure,” Dagle said.

The overloaded lines began to slowly ring with a wave pattern that repeated once every three seconds superimposed on the normal 60 Hz (60 cycles per second) alternating current frequency. That destabilized the system. “It actually broke apart,” Dagle said.

“With the phasor measurements, you could detect oscillations with enough precision to send a control signal to dampen them,” said power engineer David Hawkins, who leads the renewable power program for not-for-profit California Independent System Operator (ISO). California ISO operates most of the wholesale power grid that links power plants with utility companies for most of California.

The technology for sending such a corrective signal is not yet in place. With enough advance warning, however, more traditional controls could head off serious problems.

Phasors have long been used to assess the health of the grid, but they were values calculated from other measurements. With synchronized measurement devices placed directly on the lines, those values can now be reported many times per second, providing an instantaneous picture of the state of the grid. Previously, operators relied on numbers that were updated once every four seconds. “Imagine driving down the highway vat 65 miles per hour with your eyes closed, and every four seconds you’d open your eyes to take a peek,” Hawkins said. “Very quickly you’d be in for some unpleasant surprise.”

Efforts are now focused on improving computer programs that assemble the data and create graphic displays that provide grid operators with information they can easily use.