Thanks to advances in energy storage it is no longer just starry-eyed dreamers who see a distributed electric grid as a real possibility for North America.
More sophisticated and cheaper stationary batteries are opening the door for businesses and households to become players in electricity markets, storing energy they don’t use and selling it back to the grid.
But this democratic grid isn’t guaranteed. It takes just a few surprise failures for investors to lose faith, especially deeply cautious utilities.
So someone has to kick the tires before new battery technologies head to market. That’s the job of a federal effort called Cycling Hardware to Analyze and Ready Grid-Scale Electricity Storage (CHARGES).
Recently launched by Advanced Research Projects Agency-Energy (ARPA-E), the four-year project will test batteries under a wide-range of weather, terrain and grid conditions. DNV GL, a third-party validation company, will act as project lead for a team that includes NY-BEST, Group NIRE and CAR Technologies.
A lot gets asked of a grid battery. Some even multitask, a feature the utility industry likes. The more a battery can do at once — say offer frequency regulation as well as peak shaving — the quicker a utility can recover the battery’s costs.
Because these batteries are complex, testing their worth is neither easy nor speedy. Life cycle tests, alone, can require dozens, if not hundreds of tests and take over a year.
“This has been a major bottleneck in the industry for battery adoption,” said Davion Hill, group leader for energy & materials at DNV GL.
Cautious utilities hesitate to invest in any new technology until they’re convinced it’s thoroughly proven and cost-effective. Several lithium ion batteries can now meet this standard. CHARGES hopes to expand that pool to newer, flow battery technologies.
“We’re still trying to understand everything these batteries can do,” Hill said in a recent interview. “We’re looking at a lot of different applications.”
CHARGES is unique among ARPA-E programs in that it will evaluate technology at a more mature stage than usual. Typically, the agency takes on earlier stage inventions. This time ARPA-E is looking at batteries that passed early testing and are closer to commercialization.
“They are ready to start to demonstrate. Our role is to take them to the next step and put them through something more applied, essentially pass them through to commercialization,” Hill said.
The team will present the findings to an advisory board of potential customers. “It is a way for them to really test drive the products before they buy,” he said.
To the Big Energy Playground
Lab testing will take place at DNV GL BEST Test and Commercialization Center in Rochester, New York. Larger batteries will then undergo field tests in what Hill calls a “big energy playground,” a microgrid operated by Group NIRE at a former Air Force Base in Texas. The facility includes wind turbines, sub-system loads, storage, data collection, and other power systems.
Testing will kick off in February. In addition to evaluating battery life cycle, CHARGES will look at sizing, response time, efficiency and other performance characteristics. Hill expects the initial round of results within about six months.
This isn’t the only cutting edge battery test project for DNV GL in the fast-growing sector. The company analyzes other kinds of batteries, as well, including those for electric and hybrid ships. It also offers a MicroGrid Optimizer (MGO) tool, which will be used in CHARGES, to evaluate financial and operating parameters for microgrids.
In addition, DNV GL provided modeling for the California Energy Commission that fed into that state’s decision to require that utilities secure 1.3 GW of energy storage by 2020. The goal represents one of the biggest policy game changers, so far, for energy storage in the United States.
If all goes as planned — if batteries live up their promise — a very different electric grid is about to emerge, one free of the long-time constraint that electricity must be consumed almost as quickly as it is produced.
What will this do to electric markets? Already a new competitive player is emerging, the energy storage aggregator. (Stem and Advanced Microgrid Solutions are examples.) Aggregators install energy storage in buildings and then group the capacity into a portfolio. They then offer the combined storage as a dispatchable asset for use by the grid, perhaps for peak shaving, demand response or ancillary services.
These load aggregators, who Hill sees as poised for tremendous growth, take on the risk required to create the kind of new grid imagined in New York’s Reforming the Energy Vision (REV).
If REV, or similar distributed grid models come to be, the vertically integrated utility will be disassembled, Hill said. What does that leave the utility to do?
“They are probably going to sub out a lot of work to entities that can pull together resources for them. That’s aggregators. You can imagine a utility basically being an asset manager with aggregators underneath its umbrella,” he said.
Under this model, aggregators become the“web-forming pieces” in an electric grid that creates, stores and distributes energy much the way the Internet handles information flow, Hill said. It’s a vision that many policymakers and thought leaders are promoting. But its effectiveness depends on energy storage. And right now — for at least the next several years — batteries are the technology poised to offer storage most widely and readily. So CHARGES has a big mission: be sure this key piece of the new grid is in working order. A paradigm shift in the electricity industry depends upon it.
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