What is the most widely deployed grid-scale energy storage technology? That would be pumped hydro, with about 21 gigawatts in the U.S. and 38 gigawatts in the EU. Pumped hydro is very site-specific, and few new pumped hydro sources have come on line in the last decade.
Coming in second is compressed air energy storage (CAES) with a few hundred megawatts deployed across the globe at two sites -- one in Alabama, the other in Germany -- and a few more pilot projects in the works.
That's pumping water up a hill and pumping air into a cave, respectively, technologies that are more Flintstones than Jetsons.
Trailing a distant third are all of the other energy storage technologies -- electrochemical, thermal, gravitational and otherwise with just tens of megawatts in action -- mostly in Japan as a mandated way of firming up wind power generation using sodium sulfur (NaS) batteries from NGK.
Venture firms have sunk billions into battery, fuel cell and flow battery startups with utility-scale grid storage seen as the holy grail that turns variable energy sources like wind and solar into firm dispatchable power like coal or natural gas-fired plants. ARPA-E and the DOD are funding advanced technologies for energy storage, as well.
But there are a few problems with the electrochemical solutions -- starting with cost, long-term reliability and utility familiarity. Lithium-ion batteries might be good for cells phones and electric vehicles, but when it's time for hundreds of megawatts -- that leaves CAES.
Investigations by EPRI, the Electric Power Research Institute, indicate that up to 80 percent of the U.S. has geology suitable for CAES. A single 300-megawatt CAES plant would require 22 million cubic feet of storage space -- enough to store eight hours’ worth of electricity. CAES is relatively affordable at $1,500 per kilowatt capital cost and the two CAES plants in use have been operating reliably since 1978 and 1991, respectively.
In the middle of the night when the price of electricity is low, utilities can run compressors and pump air into a cavern or vessel at 750 psi. When the price of electricity goes up, the compressed air is preheated (with a natural gas fired burner) and the air is then used to help power a turbine. In EPRI's view, the technology is moving from diabatic to adiabatic, where the heat lost during compression is stored and used for preheating -- eliminating the need for natural gas pre-heating.
A few CAES demonstration projects:
• New York State Electric and Gas (NYSEG) is working on a CAES project in a salt cavern in upstate New York
• Pacific Gas and Electric (PG&E) is looking at a 300MW CAES project in Kern county.
I tuned into a webinar from InfoCast on Wednesday to hear an update on CAES from some experts and left with the realization that this is the technology easiest for utilities to implement because, above ground at least, it resembles the equipment that they are accustomed to working with. It's important not to underestimate the issue of familiarity when it comes to utilities and Public Utility Commissions.
According to CAREBS, "Bulk storage options CAES and PHS are the only technologies available from the marketplace today as a fully commercial proposition -- that is, financeable, with equipment supplier warranties and life cycle support, reasonable capital costs, field-proven reliability, and integrated grid operations."
Ronald Moe VP R.W. Beck, an SAIC company, asked "How do you monetize the full range of benefits from CAES?" This question applies to all storage technologies and the answer is to exploit multiple value streams in storage applications ranging from day/night price arbitrage to ancillary services. Moe spoke of two possible business models:
- Storage facility owned by or fully contracted to a regulated utility, where the value of benefits equals avoided costs
- Merchant storage facility, where the value of benefits equals market revenue less associated operating costs
Moe gave an example: say you had a 5,000-megawatt wind facility a few miles from the load with 40 percent capacity factor in all months.
Without CAES, that would require 5,000 megawatts of transmission capacity to deliver all of the generation to the load. With CAES near the wind facility, only 2,000 megawatts of transmission capacity is required. CAES makes the wind facility have the output profile of a coal plant, rather than a scarily variable wind site.
Jason Makansi, Executive Director, CAREBS noted that the U.S. has less grid storage (~2 percent) than other developed countries (most of which are already at 4 to 10 percent) and called CAES "a proven set of equipment that adds no technology risk." He also said that CAES can do for the electricity industry what natural gas storage did for the natural gas industry.
Makansi emphasized that CAES looks good because "scale is so important at the utility level," adding that "it's financeable" and "utilities have comfort with this."
He also sees bulk storage enhancing the U.S. manufacturing base and helping to increase employment.
As Greentech Media has claimed in the past, policy can trump technology in matters pertaining to electricity and energy storage. Storage, other than pumped hydro, is new and a fuzzy area without well-defined regulatory language. Is it transmission, distribution or generation? Makansi agrees, saying, "Policy framework is a complicated issue." He sees a lot getting done by the FERC at the federal level, NERC at the national level, as well as at the ISO and state level.
Makansi champions CAES, saying, "CAES can compete against today's prevailing options -- gas turbines and combined cycle solution."
There are two CAES projects deep in the development process: the Iowa Stored Energy Park (ISEP) and Central Utah's Magnum Project.
ISEP is a 270-megawatt project in the middle of Iowa's wind country.
Bob Schulte, Executive Director of ISEP said to think of it, "not as a battery but as an energy machine." Schulte added that the capital cost of $400 million is about $1,500 per kilowatt, which is less than a peaker plant but more than baseload. He described the CAES plant by saying, "Above ground it looks like a standard unit," and insisted that "It's a fully dispatchable electrical source."
Iowa is one of the leading wind states, with 3,800 megawatts of installed wind now and a just-announced addition of 500 megawatts.
This Iowa project is not a cavern; rather, it's an underground sandstone reservoir 3,000 feet down in the Mt. Simon sandstone layer. The goal is to create an air bubble in the aquifer that is a mile-and-a-half wide and 60 feet thick. The Go-No Go decision for air injection testing comes in spring or summer 2011, when large quantities of air will be injected into the site to see if the shale is a good cap.
The Western Energy Hub Project in Central Utah is located in a "strategic and rare place" according to Rob Webster, COO, Magnum Energy. The Magnum salt structure is similar to salt structures near the Gulf of Mexico, which are used to store natural gas. It's central to the Western electrical grid as well as the natural gas grid. The project is "quite far along in the gas storage permitting process."
We'll be watching the progress of these two bellwether projects. If the geology proves out and the permitting is smooth, we will likely see more CAES in the U.S. soon. Ventyx forecasts 40,000 megawatts of renewable power additions in the Western U.S. through 2034 and CAES can turn these renewables into firm, dispatchable power.
And if CAES works well, electrochemical storage might be relegated to niche storage solutions.
Image courtesy of Sandia Labs
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