Pushing the limits
Every state has a unique combination of natural resources, fuel availability, and political landscape that—more or less—defines the boundaries of acceptable power generation technology. Not every state has generous reserves of coal or oil, but many are blessed with strong winds and a citizenry that wants to put that clean resource to work.
However, there are limitations on how much wind a utility or regional authority can handle. Variables include wind's compatibility with generation types already on the power grid (natural gas and hydro work well with wind power, for example), the utility's service area size (larger areas can handle the fickle nature of wind farm production more easily), and the distribution of generating assets (the more widely they're spread out, the smoother the integration of wind power).
Developers and system planners seem to have a good handle on integration issues, if the number and size of wind farms recently commissioned is any guide. However, challenges do remain. Participants at a recent technical symposium on utility-scale wind power hosted by the IEEE, AWEA, the North American Electric Reliability Council (NERC), and the Utility Wind Integration Group (UWIG) identified the following three key integration issues.
Forecasting tools. Wind forecasting tools are needed to help system operators and managers make the most efficient use of the resources on a given system to minimize operational costs. Mark Ahlstrom of WindLogics (www.windlogics.com) noted that as forecasts become more accurate, they will be delivered to system operators in the format most useful for decision-making in the control room. Better dynamic models of wind turbines and aggregate models of wind plants are needed to perform more-accurate studies of transmission planning and system operation.
According to UWIG (www.uwig.org), fluctuations in the net load (load minus wind) caused by greater variability and uncertainty introduced by wind plants have been shown to increase system operating costs by up to about $5/MWh at wind penetration levels up to 20%. The largest part of this cost is associated with the uncertainty introduced into day-ahead unit commitment by uncertainty in day-ahead forecasts of real-time wind energy production.
A well-functioning hour-ahead and day-ahead market provides the best means of addressing the variability in wind plant output. According to UWIG, commercially available wind forecasting tools can substantially reduce the costs associated with day-ahead uncertainty. In one major study, state-of-the-art forecasting was shown to provide 80% of the benefits that would result from perfect forecasting.
Reliability. Overall grid reliability and post-fault response now can be improved by including wind capacity in the mix, thanks to new high-tech features of modern wind turbines (which have become significantly more reliable themselves). The latest set of bells and whistles includes low-voltage ride-through capability, reactive power control, voltage control, output control, and ramp rate control. Future designs are likely to sport post-fault machine response characteristics similar to those of conventional generators (for example, inertial response and governor response).
In one study of the impact of integrating 3,300 MW of wind power (10% market penetration) into New York's transmission system, system post-fault response was better with than without wind turbines, according to data from Hydro-Québec presented by GE Energy. The study concluded that the 3,300 MW are expected to increase NERC's required operating reserve margin only by 36 MW and reduce the New York Independent System Operator's annual variable costs by $350 million.
According to UWIG, wind generation may also provide some additional load-carrying capability to meet forecasted increases in system demand. This contribution is likely to be up to 40% of a typical project's nameplate rating, depending on local wind characteristics and the project's compatibility with the system load profile.
System stability studies have shown that modern wind plants equipped with power electronic controls and dynamic voltage support capability can improve system performance by damping power swings and supporting post-fault voltage recovery.
Transmission constraints. Constraints—from interconnection and grid access to tariffs and grid expansion—are a big factor in determining whether wind will become a significant part of the generation mix. Federal Energy Regulatory Commissioner Nora Brownell noted that FERC wants to be a "platform for change" and help get the rules right on interconnection, imbalance, reliability, and market access. "Being 'risk-averse' should not mean doing things the way they were done 30 years ago," she said.
Upgrades or additions to transmission facilities may be needed to provide access to remote locations with large wind energy potential. Current transmission planning processes are able to identify solutions to transmission problems, but the time required for their implementation often exceeds the time frame of project permitting and construction by several years. This fact will be the primary reason why many utilities will miss their renewable portfolio standards (RPS) goals in coming years.
Speaking as the head of NERC's Wind Energy working group, Mahendra Patel of the Pennsylvania-New Jersey-Maryland (PJM) Power Pool said that bringing more wind power on-line "is not a reliability issue" but rather a market issue, involving cost allocation among various sources. Truer words may never have been spoken.
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