For grid flexibility, utilities pushed to think beyond gas plants and storage RSS Feed

For grid flexibility, utilities pushed to think beyond gas plants and storage

When utilities and grid operators think about power system flexibility — the ability of the grid to respond to sudden changes in supply and demand — two technologies typically get the most attention.

One is the fast-ramping natural gas plant, commonly used today to help integrate intermittent renewable energy generation and meet peak system needs. The other is battery storage, due to its almost instantaneous response time and numerous potential applications for the grid.

But while storage continues to decline in price and gas plants have been buoyed by low prices for their fuel for a half-decade, there are a number of cheaper options for grid flexibility that stakeholders would do well to explore, according to a new paper.

“There is value latent in the system right now that is not being captured,” said Energy Innovation (EI) Director of Strategy Sonia Aggarwal, co-author of “Grid Flexibility: Methods for Modernizing the Power Grid.”

“There are many options for maintaining a flexible grid and many are cheaper options for meeting demand and allowing higher penetrations of variable renewables than battery storage and natural gas,” she said.

Flexibility options, ranked

To organize the multiple sources of grid flexibility profiled in the paper, EI analysts arranged them on a spectrum of grid flexibility. As the need for grid flexibility increases with time and higher penetrations of variable renewables, utilities should move from the least expensive flexibility options to costlier, more powerful ones:

The first among available opportunities would come with changes in the way resources are dispatched.

“Historical utility practice in the United States is to schedule the system at one-hour intervals,” the paper reports, “but many power systems around the world are now beginning to clear the market more frequently.”

Shortened, “sub-hourly” dispatch allows grid operators “to respond more quickly to fluctuations in electricity demand and in supply.”

Such dispatching also “matches the availability of variable renewables and in a way that better matches demand without overpaying,” Aggarwal added.

Shorter dispatch intervals can help reveal the value of resources like batteries and demand response that can match or even better natural gas plants’ rapid ramping capabilities, the paper adds. Markets like such the western Energy Imbalance Market (EIM) operated by the California ISO have already shortened their dispatch intervals — down to every five minutes, in the EIM’s case.

Another flexibility option immediately available through operational changes is the use of advanced weather forecasting.

Increasing the penetration of variable renewables need not require big investments in backup capacity, because weather forecasting can now “significantly improve system reliability,” the paper reports.

Such practices are now “granular enough to take advantage of real-time dispatch,” Aggarwal said.

Slightly further out on the time spectrum are technologies that could be implemented with “the right market products, market designs, or rate designs,” Aggarwal said.

Energy imbalance markets, such as the CAISO EIM, can enlarge a system’s portfolio of resources by “merging existing balancing areas or simply allowing for trading of electricity between existing balancing areas,” the paper reports.

An EIM requires an investment in operational software, but no new transmission infrastructure. Aross the U.S., EIMs are expected to save customers $72 million to 208 million annually, the paper adds.

“Even in advanced systems that already have sub-hourly dispatch, import schedules are pretty inflexible,” said Energy Innovation Senior Fellow Eric Gimon. “Imbalance markets address that.”

“When a diverse portfolio of energy resources is balanced over a wide geographical area, variability in the electric grid declines considerably,” the paper reports. “Variability is minimized because fluctuations in output tend be localized, so larger areas are less prone to as much variability.”

Demand response (DR) — the practice of targeting reductions in customer use to reduce peak demand — is also awaiting only the right market and rate designs. As a resource class, DR covers “a suite of demand-side options, including using more electricity when there is a surplus and using less when there is a scarcity,” the paper says.

Read full article at Utility Dive