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Feb
23rd, 2022
We’re going to need a lot more grid
storage. New iron batteries could help.
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One of the first things you see when you
visit the headquarters of ESS in Wilsonville, Oregon, is an
experimental battery module about the size of a toaster. The
company’s founders built it in their lab a decade ago to meet a
challenge they knew grid operators around the world would soon
face—storing electricity at massive scale.
Unlike today’s lithium-ion batteries,
ESS’s design largely relies on materials that are cheap, abundant,
and nontoxic: iron, salt, and water. Another difference: while
makers of lithium-ion batteries aim to make them small enough to
fit inside ever shrinking phones and laptops, each version of the
iron battery is bigger than the last.
In fact, what ESS is building today
hardly resembles a battery at all. At a loading dock on the back
side of the ESS facility, employees are assembling devices that
fill entire shipping containers. Each one has enough energy
storage capacity to power about 34 US houses for 12 hours.
The company, which last year became the
first long-duration energy storage company to go public and has
ambitions to open factories around the world, will soon begin work
on a battery that will dwarf even these truck-size versions. In
partnership with the utility company Portland General Electric,
ESS plans to construct one that will fill a half-acre building on
land adjacent to its factory. It’s expected to have almost 150
times the capacity of the biggest batteries the company ships
today.
ESS’s key innovation, though, is not
the battery’s size—it’s the chemistry and engineering that allow
utilities to bank a lot more energy than is economically feasible
with grid-connected lithium-ion batteries, which are currently
limited to about four hours of storage.
The iron “flow batteries” ESS is
building are just one of several energy storage technologies that
are suddenly in demand, thanks to the push to decarbonize the
electricity sector and stabilize the climate. As the electric grid
starts depending more on intermittent solar and wind power rather
than fossil fuels, utilities that just a couple of years ago were
looking for batteries to store two to four hours of electricity
are now asking for systems that can deliver eight hours or more.
Longer-lasting batteries will be required so that electricity is
available when people need it, rather than when it’s
generated—just as ESS’s founders anticipated.
Good chemistry
Craig Evans and Julia Song, the
founders of ESS, began working on an iron flow battery in their
garage in 2011. A married couple, they met while working for a
company developing fuel cells. Song (now the chief technology
officer of ESS) is a chemist, and Evans (ESS’s president) is an
engineer and designer.
They saw the price of renewable
energy systems dropping dramatically and predicted that this would
drive demand for energy storage. An electric grid that is 80%
powered by solar and wind, for example,
would require an affordable way to store energy for at least
12 hours.
Currently,
about 95% of the long-duration energy storage in the United
States consists of pumped-storage hydropower: water is pumped from
one reservoir to another at higher elevation, and when it’s
released later, it runs through turbines to generate electricity
on its way back down. This simple method works well but is limited
by geography.
Batteries don’t have that limitation.
However, most grid-scale batteries operating today are lithium-ion
batteries. Relatively expensive, they also deteriorate within a
few years and are made from difficult-to-recycle materials that
can
burst into flames or explode. Worse, if you want to double the
storage capacity of your battery array, you have to buy twice as
many batteries. That makes it too expensive to store energy for
longer than a few hours, says Scott Litzelman, who manages a
program that focuses on long-term energy storage at ARPA-E, the US
agency that funds research and development of advanced energy
technologies.
Flow batteries, like the one ESS
developed, store energy in tanks of liquid electrolytes—chemically
active solutions that are pumped through the battery’s
electrochemical cell to extract electrons. To increase a flow
battery’s storage capacity, you simply increase the size of its
storage tank. When the battery grows to the size of a building,
those tanks become silos.
Inside the flow battery’s electrochemical cells, two electrolytes
are separated by a membrane. One electrolyte flows past a positive
electrode as it’s pumped through the cell, and the other
electrolyte flows past a negative electrode. In ESS’s battery,
these two electrolytes are identical: iron salts dissolved in
water.
As the electrolytes flow through the
cell, chemical reactions take place on both sides of the membrane.
When an electric current is charging the battery, the electrolyte
at the battery’s negative electrode gains electrons, and dissolved
iron salts are deposited onto the electrode’s surface as solid
iron.
When the battery discharges, the
process is reversed: the electrolyte loses electrons at its
negative electrode, the plated iron returns to its dissolved form,
and the chemical energy in the electrolyte is converted back to
electricity. At the positive electrode, the opposite process
occurs: the electrolyte loses electrons and “rusts” to a brownish
fluid while the battery is charging, and this process reverses
during discharge.
In a conventional lithium-ion battery
like the one in a mobile phone or electric car, the cell and
electrolyte are contained inside a single package. “What you have
at the start is what you get,” says Evans.
But with a flow battery, keeping the
electrolyte in an external tank means that the energy-storing part
is separate from the power-producing part. This decoupling of
energy and power enables a utility to add more energy storage
without also adding more electrochemical battery cells.
The trade-off is that iron batteries
have much lower energy density, which means they can’t store as
much energy as a lithium-ion battery of the same weight. And flow
batteries require more up-front investment and maintenance than
lithium-ion batteries.
However, when it comes to safely
storing large amounts of energy for long periods, they’re hard to
beat. And that’s exactly what grid operators will need to do a lot
more of in the coming years.
Long-lasting
The batteries that utilities use
today typically store power for four hours or less. That’s fine
for tasks such as smoothing out short-lived frequency fluctuations
and supply drops, but as the electricity sector moves toward 100%
clean energy, “you absolutely can’t do it with four-hour
batteries,” says Hugh McDermott, senior vice president for sales
and business development at ESS.
To accommodate the ups and downs of
solar and wind generation, most grid operators use natural-gas
“peaker plants,” which can start up rapidly when electricity is in
high demand. A battery that can provide 16 hours of storage would
be cheaper to install than any peaking system, McDermott says.
Flow batteries are a small but growing
part of the grid-storage market. By the end of 2019, they were used in
only 1% of large-scale battery installations in the United States,
according to
an August 2021 update by the US Energy Information Administration
on trends in the battery storage market. A few utilities began
installing large-scale flow batteries in 2016 and 2017, but those
batteries use a vanadium-based electrolyte rather than iron. Vanadium
works well, but it’s expensive.
Evans and Song initially set out to
design a vanadium flow battery but changed course when they stumbled
across some iron-based chemistry done at Case Western Reserve
University in 1981. Iron struck them as a low-cost alternative to
vanadium, “but it had challenges,” says Evans.
One challenge was how to prevent roughly
1% of the electrons on the negative side of the battery from bonding
with stray hydrogen ions in the water-based electrolyte instead of
plating iron. Over time, this side reaction generates a buildup of
hydrogen gas and causes the two sides of the battery to depart from a
chemical balance in which both electrolytes return to their original,
identical state when fully discharged.
“All batteries have side reactions,”
says Evans. But because it’s easy to access the chemicals that
circulate through a flow battery (unlike the chemicals closed
inside a conventional battery), designers can include a mechanism
to recover from these side reactions.
Evans and Song dealt with the problem
by adding a “proton pump” to their battery. It’s a fuel-cell-like
unit that converts hydrogen gas back to protons, which reduces the
pH of the electrolyte and brings the two sides of the battery back
to the same state of charge. With the pump, the battery is
expected to be able to cycle an unlimited number of times, for at
least 20 years.
At Case Western, researchers have
tried another approach: plating dissolved iron onto the particles
in an iron slurry rather than onto a fixed electrode, so that the
plated metal is stored in the battery’s external tank. It worked
well in smaller cells, but in bigger cells the slurry caused
clogs.
Both Case Western and ESS have received
ARPA-E funding to build and demonstrate iron flow batteries. The
$2.8 million, five-year
grant ESS received in 2012 enabled the company to develop the
proton pump and move to commercial production.
Breakthrough Energy Ventures, a fund
established by Bill Gates and other investors concerned about
climate change, has also backed ESS. The company sold its first
product in 2015: a battery that enabled a California vineyard to
store solar energy during the day and power an irrigation system
in the evening.
Today ESS has a backlog of orders for
its shipping-container-size battery, which has a capacity of up to
500 kilowatt-hours. The company has begun delivering some to SB
Energy, a clean-energy subsidiary of SoftBank, which agreed to buy
a record two gigawatt-hours of battery storage systems from ESS
over the next four years. The deal is valued at more than $300
million.
Buying time
ESS batteries can currently hold four
to 12 hours of charge depending on how they’re configured, but
eventually some energy-storage systems may need to work for days
or even weeks to accommodate seasonal fluctuations in wind power.
Massachusetts-based Form Energy is developing an
iron-air battery
technology, which uses oxygen from ambient air in a reversible
reaction that converts iron to rust. The company claims its
battery could store power for up to 100 hours. Its first
installation will be a one-megawatt pilot plant in Minnesota,
scheduled to be completed in 2023.
Utilities aren’t just thinking about
how to store energy as they move toward renewables; they’re also
thinking about how to make the grid more resilient to extreme
weather and other effects of climate change. Long-duration
batteries have a role to play there, too.
In a project with San Diego Gas &
Electric, ESS’s iron flow batteries will be paired with a solar
array in the wildfire-prone town of Cameron Corners, California.
If the utility needs to shut down transmission lines to prevent or
respond to a fire, the solar-battery microgrid can keep the town’s
critical services functioning. The project is slated to come
online later this year.ESS’s
Wilsonville facility has room to ramp up production, but
the number of orders it gets will depend to a large extent on
the fate of clean-energy tax credits that are part of the Build
Back Better bill currently stalled in Congress. Proponents of
energy storage argue that long-duration storage deserves the same
incentives as renewable energy.
If lawmakers agree, those credits
could help make energy storage technologies like the iron flow
battery cheap enough for utilities to begin using them widely.
Both
the ARPA-E program and the US Energy Department’s
Long Duration Storage Shot aim to have cost-competitive
systems that can store 10-plus hours of energy on the market
within a decade.
For ARPA-E, that means getting the
levelized cost of energy storage—which takes into account all
costs incurred and energy produced over a lifetime—down to less
than five cents per kilowatt-hour, Litzelman says, which would be
a 90% reduction from 2020. The initial cost of a battery is just
part of that equation.Flow
batteries aren’t the only promising technology being developed for
long-duration energy storage. Other companies and researchers are
experimenting with different types of batteries, as well as with
hydrogen storage and mechanical systems such as compressed air or
“mobile masses” that are hoisted and lowered to convert electrical
energy to kinetic energy. One experimental system funded by ARPA-E
stores energy by pumping water into rocks, and extracts energy
when the water gets squeezed back out.
All these systems have a shared goal,
says Litzelman: “24/7 clean energy.” Getting there will very
likely require multiple new storage technologies, and many more
companies will have to reach the point where ESS is today. Unless,
of course,
a different kind of technology breaks through.
Green Play Ammonia™, Yielder® NFuel Energy.
Spokane, Washington. 99212
www.exactrix.com
509 995 1879 cell, Pacific.
Nathan1@greenplayammonia.com
exactrix@exactrix.com
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