ERCOT in February averted a blackout that could have become a disastrous defining moment for the windpower industry. This near miss can teach utilities and system operators valuable lessons about...
Forecasting brings wind energy under control.
stakeholders in the Midwest Independent Transmission System Operator (MISO) convened to discuss critical issues facing the ISO. The issue of integrating wind energy into the network ranked foremost on the agenda.
MISO’s focus on wind isn’t surprising, given the fast-growing role of wind for powering the network; wind capacity in MISO nearly doubled in 2009, going from 4,300 MW in 2008 to more than 7,600 MW today. And MISO counts more than 60,000 MW of proposed projects within its footprint. Accordingly, the MISO is making tariff and rule changes to bring wind fully into the fold.
“Right now wind farms are considered price takers,” says Michael McMullen, director of MISO’s West regional operations. “But we’re developing a ‘dispatchable intermittent’ feature that would allow wind farms to register as dispatchable generators. They’d be treated the same as traditional generators.”
Resources registered as “dispatchable intermittent” wouldn’t be counted on for regulating or contingency reserves, but from a market perspective they could offer and sell power into the MISO market on the same terms as other dispatchable generators—with one exception; the ISO would dispatch these resources up to the maximum megawatt-output figures provided by a real-time forecasting system, rather than the amount the generators offer to the market.
Real-time forecasting is the key. MISO has been using a centralized wind energy forecasting system since mid-2008. The system, provided by Energie & Meteo of Oldenburg, Germany, provides MISO operators with hourly wind forecast data for a seven-day period. McMullen says operators rely mostly on intra-day and day-ahead forecasts. “Getting forecasting data in house gives you a great big jump forward to see within an hour or two, when wind output will be ramping up or down,” he says.
Wind forecasting has obvious appeal for system operators, especially those in sprawling, wind-rich areas like the nearly 1-million square mile MISO region. “Very large balancing areas with adequate transmission take maximum advantage of diversity in both load and wind generation,” stated an exhaustive study of wind-integration potential in the Eastern Interconnection, published in January 2010 by engineering-consulting firm EnerNex, under contract with the DOE’s National Renewable Energy Laboratory (NREL). 1 Size matters when it comes to centralized wind forecasting.
“Geographic diversity benefits the accuracy of an aggregated forecast,” McMullen says. “It means that if you happen to miss the timing of a wind ramp in one place, it probably is hitting someplace else. We recognize that as a benefit that gives us some nice accuracy numbers in current and next-day forecasting.”
Specifically, while state-of-the-art forecasting technologies for a specific plant might predict, on average, day-ahead wind output with error rates between 12 and 20 percent, aggregating forecasts across a whole region can cut those error rates in half or better, to around 5 percent ( see Figure 1 ). Such numbers, calculated as a factor of installed capacity, might be a bit deceiving; on average, wind farms generate about 30 percent of their nameplate capacity. Nevertheless, with forecast error rates falling into the single digits, wind starts to more closely resemble the other major variable on the grid—shifting