By Jonathan Marshall
In the 1980s, awed by Japan’s industrial successes, U.S. management consultants began touting the merits of “just-in-time” production. Little did some of them know, America’s electric utilities began practicing that approach a century earlier.
Since storing electricity is difficult and expensive, utilities generally produce only as many electrons as customers demand at any given time. They match supply to demand by ramping generation up and down as needed to avoid catastrophic imbalances that can black out an entire region.
But as utilities like PG&E acquire more clean but intermittent wind and solar energy, which can fluctuate widely from hour to hour and even minute to minute, they find it harder to fine-tune supply as needed. That’s why coming up with cost-effective forms of energy storage has become a leading priority for grid operators and regulators as well as utilities.
Energy storage can allow utilities to even out the ebb and flow of unruly sources of renewable energy. It can let utilities take advantage of excess wind energy at night, when demand is low, and put it to use during peak daytime hours. It can let utilities delay upgrading transmission or distribution equipment by serving local demand peaks from a source physically close to customers.
James Boyd, vice chair of the California Energy Commission, said in 2010, “Energy storage will become critical as we migrate to California’s future ‘smart grid’ and integrate renewable energy sources, manage peak demand, and relieve transmission line congestion.”
PG&E is an old hand at energy storage, as one of the nation’s leading owners of large-scale pumped storage. At the Helms hydroelectric facility in the mountains east of Fresno, PG&E releases water from a dam to drive clean generators when demand is high. Captured in a lower reservoir, the water is then pumped back up when demand and energy prices are low.
Now PG&E is on the forefront of testing applications for smaller-scale storage such as batteries. The utility recently deployed a two-megawatt sodium-sulfur battery pilot project at its Vaca Dixon substation to test potential applications of energy storage on the grid. PG&E is also installing a four-megawatt battery at the end of a distribution feeder in San Jose, to test applications including improving service reliability and power quality to customers. Tests will also gauge factors such as battery efficiency and remote operation by telemetry. (See the accompanying video for a more detailed look at these two PG&E pilot projects.)
PG&E is conducting the studies under contract with the California Energy Commission and in collaboration with the Electric Power Research Institute, an R&D resource for the electric utility industry.
The timing of the project is opportune, as PG&E and other electric utilities in California race to meet the state’s ambitious mandate to supply a third of all electricity sales from eligible renewable resources by 2020. For state officials as well as utilities, determining whether storage technology is a feasible way to reliably integrate so much renewable energy onto the California grid is a high priority.
Many other utilities around the world are also investigating battery storage. AES Energy Technologies is working on a 32 MW battery deployment at a West Virginia wind farm, while Toronto Hydro seeks to test a much smaller application at a community center in New York. Duke Energy Renewables announced in January that it recently completed a 36-MW battery storage and power management project at a West Texas wind farm. And Sacramento Municipal Utility District is looking into the potential for meeting peak demand in residential neighborhoods with local lithium-ion batteries.
Although storage looks attractive on paper, there are a host of unanswered questions about safety, reliability, flexibility, and cost. The range of technology options—including pumped hydro, compressed air, flywheels, and numerous battery chemistries—is daunting. Storage must also compete with other possible solutions, including flexible gas-fired generation and “demand response” programs that balance supply and demand by altering customer demand rather than electric supply.
Steven Berberich, president and CEO of the California Independent System Operator, which manages the state’s power grid, said last year of energy storage, “It’s not a matter of if — it’s a matter of when. . . . Storage plus renewables is a marriage made in heaven.” But he also acknowledged “it’s expensive — and it has to come down in price. . . . It’s the economics of storage we need to sort out.”
Email Jonathan Marshall at firstname.lastname@example.org.