As the electric grid is increasingly powered by renewables, it will need energy storage for when the wind isn’t blowing and the sun isn’t shining. But the three top grid-scale energy storage technologies today—pumped hydropower, lithium-ion batteries and “flow” batteries—arguably, aren’t up to the challenge.
The U.S. Department of Energy’s technology incubator ARPA-E (Advanced Research Projects Agency-Energy) wants to change that. It’s going long on a number of high-risk, high-reward R&D projects that might change the entire grid storage equation. U.S. Energy Secretary Ernest Moniz has said he thinks grid-scale battery storage will be the key innovation that enables the grid to completely decarbonize by midcentury.
“There’s a lot of discussion about what the grid of the future will look like,” says Eric Rohlfing, ARPA-E Deputy Director for Technology. “Of course what we want to do is enable much higher penetration of renewables. So storage is an obvious way to do that… The two key points of grid storage are: it has to be cheap, and it has to be durable—to go through a lot of cycles.”
Here’s the grid-energy storage landscape today: Pumped hydropower, in which excess electric power pumps water uphill and is returned to the grid using water turbines when that water is released back downhill, makes up 95 percent of today’s grid-scale energy storage, according to ARPA-E. In total, it contributes 20.4 gigawatts of generating capacity to the grid. However, pumped hydro requires compliance with land use and environmental regulations, huge supplies of water, and big hills to pump the water up. So, while it’s reliable and cheap, it’s not broadly or universally scalable.
Lithium-ion batteries have powered the consumer electronics revolution of the past 30 years, but they’re also expensive, compared to, say, pumped hydro. And their flammability, as Samsung Galaxy Note 7 customers know, could be more than just an inconvenience if a grid-sized battery farm went full Hindenburg with a flame out. So, at the grid scale, lithium ions could perhaps only be scored partly reliable, affordable, or scalable.
The flow battery, another promising technology, stores its power in vats of electrolyte; it’s scaled up simply by adding more vats. Though flow batteries represent a new frontier of grid-scale reliability, at present they’re also expensive.
According to a recent report, ARPA-E has invested $85 million in energy storage research projects since 2009. The website for ARPA-E chronicles some 73 projects at companies, labs, and universities—among them, MIT, Harvard, Stanford, UCLA, Penn State, Oak Ridge National Laboratory, Lawrence Livermore National Laboratory, Ford, Boeing and General Electric.
Today there are already grid-scale energy storage technologies based on simple scientific principles that everyone learned in high school physics. Lift a mass m to a height h, and its gravitational potential energy is m times h times the acceleration due to gravity (9.8 meters per second squared).
All of which means unused energy on the grid can be readily stored in the form of mass—typically, water or slabs of metal or concrete—that’s been lifted or pumped up a hill. Then when the grid needs that energy, what’s gone up is allowed to come down, and the stored energy is then recaptured via water turbines or regenerative braking devices.
In April, the U.S. Bureau of Land Management granted the California-based company Advanced Rail Energy Storage, or ARES, a right-of-way lease to test out a rocks-on-railcars energy storage idea on a 43-hectare parcel of public land in southern Nevada. The ARES project is expected to store 12.5 megawatt-hours of energy with 50 megawatts of power capacity. And according to the company, its patented technology can be scaled up. As ARES’s CEO James Kelly told the electric utility industry blog Utility Dive in April: “If we had a 500-MW project, we could double the capacity, and it would only increase capital costs by 20 percent.”
On the other hand, says Rohlfing, pumped hydropower is limited in a crucial way:
It can’t be deployed everywhere. Let’s say you want to alleviate the problem of storage in the [U.S.] desert southwest. Where are you going to get the hydro, and where are you going to pump it? There need to be a variety of solutions to address the storage problem. Pumped hydro is demonstrated, it’s successful, and it’s low cost. And, in fact, that was one of the drivers for electrochemical batteries. We wanted to be as cheap as pumped hydro. That’s challenging. That’s very hard.
With that in mind, ARPA-E has set some lofty goals for the electrochemical battery research it supports: a price of $100 per installed kilowatt-hour of grid storage; 5000 charge-discharge cycles (i.e. 10 years of system life); and a roundtrip efficiency of 80 percent or greater per charge-discharge cycle.
Of the 73 energy storage projects listed on ARPA-E’s website, the agency recognizes eight grid-storage technologies that it says are very promising and/or well along the path to wide-scale deployment. (IEEE Spectrum will feature an interview with representatives from two of those eight ARPA-E-highlighted storage projects in future posts.)
In general, says Rohlfing, electrochemical batteries still rank among the most promising energy storage technologies—but not necessarily the lithium-ion kind that Elon Musk touts with his Tesla Powerwall home storage system.
“It’s very logical what Tesla and others are doing to say ‘We’re going to use lithium-ion for grid-scale storage,’” Rohlfing says. “Lithium ion has a lot of attributes, and high power is one of them. But it doesn’t necessarily mean it’s the right choice for [the] grid. It is the most mature battery technology, so it is of course what you can buy today, and what companies will give you a warrantee for. There's 30 years worth of development.
“For our projects, it’s a projection. They’re very early stage still. They’re just starting to get customers. They haven’t had the advantage of a long development cycle and a lot of scale-up activity. So where they’ll wind up going in price and performance is not clear. But we think that they have great promise.”
At the moment, Rohlfing says, the flow battery is one of the leading prospects for grid-scale storage because they are like a cross between a standard battery and a fuel cell. Again, expanding the capacity of a flow battery is as simple as adding another tank of electrolyte.
“You have two large tanks [one on the anode side, and one on the cathode side of a membrane]; you can store a lot of energy in those, and you can ramp up that energy scaling quite easily,” Rohlfing says. “When we first started, the state of the art was all-vanadium flow batteries, which are very expensive, because vanadium is expensive. All our projects are looking to lower that cost.”
The element vanadium, often mined from magnetite in South Africa, Russia, and China, costs $3500 or more per kilogram at high-purity concentrations of 99.9 percent.
ARPA-E-funded flow battery research projects have tried to drop the cost by cutting out the vanadium altogether. For instance, a version produced by Energy Storage Systems uses iron chloride chemistry instead—which, as Rohlfing says, is “rust cheap.”
Another variant, now being investigated by a team at Harvard, relies on nature for its electrolyte. The group is now zeroing in on an organic compound called a quinone that’s very similar to a chemical found in rhubarb.
“It’s looking at the question of how can we take a very cheap material, organic molecules, and optimize those for use in a flow battery,” Rohlfing says. “They did a fascinating job of screening a huge number of compounds to find the right class of quinones that could function well in a flow battery. They’ve made enormous progress. They have a company spun out. It’s not producing a product yet…But it highlights the advantage of flow batteries. You have an inexpensive material in a tank. And when you want to replenish it, you just refill the tank.”