Flow batteries -- energy storage systems that pump electrolyte through stacks of electrochemical cells -- are one of the few battery formats that hold promise for affordably storing energy for multiple hours at a time. That’s a valuable feature for grid-scale energy storage, and over the past few years, we’ve seen a host of flow batteries emerge to tackle that challenge, using a variety of chemistries seeking the right combination of efficiency, practicality, and cost-effectiveness.
Vanadium redox flow batteries are one of the most promising chemistries, because of vanadium’s ability to maintain different states of charge as a standalone element, unlike other chemistries like zinc-bromine or iron-chromium. But getting these efficiency advantages from theoretical to real-world working model status has taken years of effort -- and some significant changes along the way.
In particular, the Department of Energy’s Pacific Northwest National Laboratory (PNNL) has in recent years developed a new vanadium electrolyte, one with the promise of increasing energy storage capacity by 70 percent from previous versions. The new electrolyte can also increase the operating temperatures of the batteries they’re used in, giving them more power delivery punch, as well as a potentially longer lifespan.
So far, three companies have licensed this PNNL technology, according to Russ Weed, vice president of business development and general counsel for Mukilteo, Wash.-based UniEnergy Technologies. The first is Imergy, the Fremont, Calif.-based startup formerly known as Deeya, which switched from iron-chrome to vanadium flow battery technology last year. The second is WattJoule, a Massachusetts-based startup.
The third is UniEnergy, which was founded in 2012 and has raised more than $20 million from private investors, he said. But while those first two companies are now working on prototypes of the new technology, UniEnergy is already bringing this “third-generation” vanadium redox flow battery technology to commercial scale, he said.
In fact, the startup plans to make 3.5 megawatts of its Uni.System containerized batteries this year, and “all of them have homes,” he said. That includes 2 megawatts for home-state utility Snohomish PUD, 1 megawatt for Pacific Northwest utility Avista, and a 500-kilowatt system set to be deployed in an as-yet-undisclosed location in California this year.
UniEnergy was helped by a strategic partner in making this jump from licensing a brand-new technology to putting integrated energy storage units into the field, Weed noted. One of UniEnergy’s investors, China's Bolong Industrial Investment Co., is also an investor in Rongke Power, a Chinese company that’s been making vanadium flow batteries for the past eight years, using an older type of electrolyte, he said. (This is the same type of electrolyte used in vanadium redox flow batteries made by large-scale manufacturers like Sumitomo, which is installing a 60-megawatt-hour system in Japan and has broader commercialization plans, and Gildemeister-DMG Mori Seiki, which makes the CellCube system now being deployed in Europe and, more recently, in New York City.)
UniEnergy has built on Rongke’s work to design the 600-kilowatt peak, 2-megawatt-hour maximum containerized energy storage systems it’s now deploying, Weed said. One of these installations, as pictured above, consists of five 20-foot containers. Four of them contain flow battery systems with 150 kilowatts and 500 kilowatt-hours each of capacity, and the fifth contains the inverters and power electronics that convert this DC power to grid-ready AC.
Another advantage for UniEnergy is the fact that its co-founders, CEO Z. Gary Yang and CTO Liyu Li, are the same PNNL scientists who were deeply involved in the lab’s development of this new vanadium electrolyte, Weed said. The company continues to invest money into research and development to increase power output, improve utilization rate efficiency, and otherwise better the operating characteristics of its systems.
UniEnergy plans to manufacture 18 megawatts of its storage systems next year, and “those we’re very actively seeking homes for,” Weed said. With its 67,000-square-foot facility, the startup could scale up to producing up to 100 megawatts of systems per year, he added.
As for the cost of UniEnergy’s system, the startup isn’t disclosing any hard figures right now, but Weed said that a typical installation today will cost “somewhere between, let’s say, $700 and $800 per kilowatt-hour,” a figure that includes all the components needed to interconnect with the grid. “When we scale up to where we’re going, we’re going to be $500 per kilowatt-hour, all in,” he said.
That cost is quite competitive with other flow batteries on the market today, though it’s being challenged on the low end by startups like Imergy, which is aiming to deliver its vanadium redox flow batteries at $500 per kilowatt-hour with its current systems, and drop that to $300 per kilowatt-hour by using recycled vanadium for its electrolyte, among other improvements.
Emerging closed-battery technologies, such as Eos’ zinc-based batteries, Aquion’s sodium-aqueous batteries or Ambri’s liquid-metal batteries, are also promising long-duration energy storage at similarly low price points. But right now, only Aquion is selling its batteries at commercial scale.
Flow batteries do have drawbacks compared to other grid-scale energy storage options like sodium-sulfur or lithium-ion batteries. One major issue is their relatively low (65 percent to 70 percent) “round-trip efficiency,” a measure of how much electricity comes out of them per unit of electricity going in. That’s a low figure, compared to lithium-ion batteries, which have round-trip efficiencies in the 90+ percent range.
But flow batteries have some significant advantages over lithium-ion batteries and other closed battery systems when it comes to long-duration energy storage. Beyond being designed for this multi-hour storage function, flow batteries can add more electrolyte to existing systems to increase their capacity, while lithium-ion and other “closed” battery systems are stuck with whatever kilowatt/kilowatt-hour ratio they’re designed to achieve.
There are plenty of grid-scale energy storage applications that are just fine for short-duration energy storage -- think of the lithium-ion batteries being used today for grid frequency regulation, or to supply peak-shaving power for buildings. But many other applications being considered for energy storage will require multiple hours of storage at a time -- consider California’s plan to create a flexible capacity resource for its solar-rich grid, which in its present form would require systems to store at least two hours of energy at a time to meet the grid’s needs.
California, which has set a goal of getting 1.3 gigawatts of energy storage on its grid by 2020, is an important testing ground for determining what mix of of long-duration and short-duration storage systems are best suited for meeting a variety of grid needs. UniEnergy plans to bring a 500-kilowatt system it's been testing at its headquarters to California, where it will be connected to an industrial site for further testing, Weed said.
Right now, UniEnergy’s customers are considering its flow batteries for use in a range of grid needs, ranging from multi-hour load-shifting and outage support, to voltage and frequency regulation functions now served by lithium-ion batteries, he said. “We can do peak shaving (or time shifting)...and frequency regulation concurrently,” he noted. “We have test results proving we can do it.”