North American SynchroPhasor Initiative officials report ‘great progress’

Officials of the North American SynchroPhasor Initivative (NASPI) report “great progress” in the effort to install and network phasor measurement units (PMUs) on the transmission grid across North America.

Speaking with TransmissionHub following a presentation on the grid of the future at the 125th Annual Meeting of the National Association of Regulatory Utility Commissioners (NARUC) in Orlando, Fla., last week, Terry Boston, PJM Interconnection president and CEO, and NASPI’s chair, and Allison Silverstein, NASPI project manager, explained that, in many ways, that future grid is already here.

As of today, “400 units have been installed in PJM alone and over 1,000 across North America that are operational and networked, and they area high-quality production grade as opposed to the research grade units that were installed during the first decade of PMUs’ history,” Silverstein said.

PMUs have been installed across the entire Western Interconnection and across parts of the Eastern Interconnection as well.

The need for PMUs, which gather and transmit data points as frequently as 30 times a second, became obvious following the East Coast blackout of Aug. 14, 2003.

“One of the most important things that came out of that was the need for time-synchronized data and wide-area visibility,” Boston said. “The conclusion was that phasor measurement units were the best way to get there.”

Boston chaired the North American Electricity Standards Board (NAESB) committee investigation following the 2003 blackout.

There has been a significant amount of effort put in over the last three years to establish data networking, to debug and work out communications issues, and to develop high-quality software so the PMUs can be used for operational applications as well as off-line applications, Silverstein said. The next step is tying them together with a robust data-sharing network.

“When we started this game, we thought all we had to do was put out PMUs and the magic would happen,” Silverstein said. “It turns out, first, you have to put out the PMUs, and then you have to build the system. Devices are simple; systems are hard.”

To that end, an initiative is now underway to build the Eastern Interconnection Data Sharing network, which will initially share current operational data, and will progress to shipping high-speed synchrophasor data between reliability coordinators within one to two years.

“We have a tremendous amount of data coming in” that requires further analysis, Boston said. “We have to farm it to determine when to alarm it and when to take action in the control room.”

To a large extent, such data has been available for a number of years but, without a synchronized method of time coding, data coordination was more difficult.

“In the 2003 blackout, it took us six months to get the sequence of events of what went wrong on the system,” Boston said. “During the San Diego outage [in September 2011], it took six hours to get the sequence of events.”

Having time-synchronized data is valuable from a forensics point of view, but forestalling such events is the next hurdle.

“How do we get to blackout prevention instead of blackout investigation?” Boston said. “How do we get it in the control room with the alarm systems and the controls and, to some extent … advise the operator of what steps he should take to redispatch the system.”

While that functionality may be several years down the road, there are other functions in which PMUs are providing value to the industry. Those different sets of uses for PMU data, including forensics, model validation and planning, are at different stages of readiness.

“One of the huge waves of value that is being realized is that PJM and [the Bonneville Power Administration] both have requirements in place that every single new large generator have a PMU at its point of interconnection,” Silverstein said.

Having PMUs at each generator provides a large amount of information, including how any given generator reacts to a disturbance on the grid.

That data enables the operator to validate the generator model used to predict how the device will react, and there have been many power plants where this testing has determined that the model needs to be improved, Silverstein said. In addition, assessing a generator model’s performance in real time using PMUs is more economical than other methods of evaluating the model’s performance.

“The alternative way to meet the NERC modeling requirements is to take your generator offline for several days and do an extensive set of tests, which means no revenue,” Silverstein said. “Using a PMU for generator model validation saves a tremendous amount of money.”

Boston called such an application a two-way street, noting, “You use your models to look for anomalies in the data that’s coming in, and you use the data that’s coming in to look for anomalies in the model.”

More to come

The next level of model validation that will use PMUs is system data. PJM and other grid operators are using phasor data to validate their state estimators, which are critical for system operations, Silverstein said. The operators are also using PMUs to feed real-time data into the state estimator so they have more real-time information.

“One of the most important things we need to do to set up operational [uses of the PMU data] beyond wide-area visualization in real time, which we have today, so we can [do] things like use phase angles to monitor the stability of the system and use voltage monitoring to determine whether there are any emerging problems in specific spots,” Silverstein said. “We are beginning to archive the information and conduct a long set of complicated data mining and pattern recognition efforts to begin to develop diagnostic and predictive tools and operator decision support tools.”

That can’t happen overnight.

“Until you have all of that data cleanly analyzed over an extensive period of time and [varying] grid conditions, you don’t want to be telling the operator to act upon this if you don’t have total confidence on what it’s implications are,” she said.

Accordingly, Boston is not in favor of automating the system just yet.

“We want to make sure it’s mature before we move” to system automation using PMU data, he said. “With any new technology you want to be sure that you’ve thoroughly tested it before you turn it into an automated system.”

Contributions to fund NASPI, which came from the U.S. Department of Energy (DOE) and industry members, totaled more than $600m, an amount which both officials said could be easily offset by a single prevented outage or a capacity increase at a single flowgate.

“Based on the Aug. 14, 2003 [blackout], which was a $6bn day, you’re talking about two hours of reduced outage time” to recover the investment, Boston said.

Silverstein said increased efficiency of both transmission and generation assets will also yield measurable returns on investment.

“One generator using [a PMU] saved itself $800,000 in revenues” that would have been lost if it had to go offline for NERC model validation, she said.

Silverstein also pointed out that, using PMU data, the operators of the California-Oregon intertie determined that the parameters set for the intertie’s throughput were too narrow and uprated the intertie by 100 MW as a result.

She said, “100 MW of trade year-round between California and Oregon is worth $200m per year.”

Now that NERC is stepping out of the technology incubation business, DOE and the Electric Power Research Institute have stepped forward to take over NASPI “because they thought the value of this collaboration was so important,” Silverstein said. “DOE will be supporting NASPI in 2014 and 2015 so we can continue this joint problem-solving effort.”