When the long-awaited solar eclipse hit Europe on March 20, 2015, Germany held its breath. With more solar power capacity than any other nation, the country of 82 million was hit hard when up to 80% of its sunlight was cut off.
On any given day, as much as 40% of Germany’s electricity is provided by solar power, so the country’s four major electricity networks had spent months preparing for the drastic drop in solar electricity input as well as the rapid increase in solar power that resulted when the eclipse finally came to an end. Any drop could lead to blackouts, while a surge in the wake of the eclipse could trip circuit breakers or overwhelm transmission lines.
So engineers took measures to stabilize the grid and the electricity supply. They planned on drawing more heavily from fossil fuel, nuclear, and hydro plants, while also asking four aluminum smelters to dial briefly back their demand.
Then the eclipse happened. Immediately before, German solar panels were pumping out a combined 21.7 GW of electricity. At the eclipse’s peak, it dropped to 6.2 GW, and rebounded to 15 GW after the moon had passed. Despite the seesaw in production, the event passed without a major disturbance. The German power grid didn’t collapse as some had feared.
This August, the U.S. will face its own test when a total eclipse casts an arcing, transitory shadow more than 60 miles wide from Oregon to South Carolina. Even states that are untouched by the totality are racing to prepare for the drop in electricity production. California, for example, is bracing for a 6 GW surge in demand over supply during the event. The rate at which supply sags and eventually returns is anticipated to be two to three times the usual rate at which grid operators respond, according to the California Independent System Operator.
Eclipses are extreme versions of events that happen every day. The sun may duck behind a cloud, and the wind may stop blowing. That intermittency poses a challenge, but it’s not an unsolvable problem.
As renewable energy sources like wind and solar drop in price and become competitive with new fossil fuel plants—something which has already happened in Africa and China—grid operators will need better tools to balance supply and demand. More detailed and accurate weather forecasts will certainly help by predicting when and where sun and wind will be plentiful. But more than that, energy storage will play a key role keeping the grid flexible and adaptable, says Apurba Sakti, a research scientist at the MIT Energy Initiative focusing on energy storage technologies. “It helps you store at times of excess generation that you can then use later on when the sun in not shining or wind is now blowing,” he says. And that could keep the lights on as renewables ramp up.
Germany’s North Rhine-Westphalia was once known as “the land of coal and steel.” Hundreds of mines once dotted the landscape, and while many have shut down, several still remain, including the old Prosper-Haniel coal mine that has been running for nearly half a century. It’s hard to miss the colossal, lime-green headframe that looms over the city.
But after next year, the tower will be conspicuous in its absence—when the tangle of steel will be replaced with wind turbines, an artificial reservoir, solar panels, and more. Last month, the German federal government, which has been working alongside private engineering firms since 2012, made plans to transform the coal mine into a giant battery. If the project proves successful, the site will provide the reliable energy that solar and wind can’t always promise to 400,000 homes.
The 600-meter deep mine creates an artificial elevation, which makes this coal mine a prime location for hydroelectric storage. Typically, so-called pumped storage plants operate by shuffling water between two reservoirs, one higher than the other. Excess electricity is used to pump water into the higher reservoir, where it sits until grid operators open the gates, sending the water downhill, through the turbines, and into the lower reservoir.
The Prosper-Haniel battery will work in a similar fashion, except the mine tunnels will replace the lower reservoir. When all the water has streamed through, it’ll be pumped back up to the top of the mine at night when the price is cheaper and demand is lower. “The German coal mine is interesting,” George Baker, president of Vcharge, a transactive electric storage technology company that provides market-based energy distribution optimization, says. “That’s a huge reservoir, not compared to natural reservoirs, but still.”
Baker says Germany’s wildly fluctuating energy crises has states like North Rhine-Westphalia looking for a large-scale solution to balancing its renewable energy. When the sun comes up or the wind starts blowing in Germany, supply often exceeds demand. As a result, prices tumble, often going negative, meaning that power stations need to pay people to use their electricity. Traditional fossil fuel power plants have a hard time producing power economically when demand ebbs and flows so frequently.
Batteries are an obvious solution, and though prices are likely to continue their steady march downward, they’re currently expensive. “Pumped hydro[electric storage] is at present the only commercially viable grid-scale storage technology,” Baker says. Pumped hydro is probably the most important asset in managing the balance of energy grids because it can go from generating energy quickly when needed to efficiently storing energy when electricity is cheap and abundant. Plus, it’s a proven technology, having been around since the 1980s.
But pumped hydropower isn’t a universal solution. For one, it needs a very particular kind of geography, like a reservoir at the top of a mountain or a disused coal mine. And two, water needs to be plentiful. So while pumped hydro works and works well in many cases, engineers are exploring other options to keep the lights on when the sun sets.
Up and Down and Up Again
More than 5,000 miles away from North Rhine-Westphalia, in southern California, there’s buzz about rather plain-looking railcars that don’t transport people or goods or really go anywhere at all. They’re owned by a Santa Barbara-based startup called Advanced Rail Energy Storage (ARES), and they’re another contender in the grid storage market.
When electricity is cheap, ARES electric locomotives draw power from the grid to haul heavy railcars up a hill. Once they’re at the top, the potential energy they embody acts as storage. When the grid needs electricity, the brakes release and the cars begin to inch downhill. The motors that hauled them up turn into generators, controlling the descent and generating power as they go. It’s essentially the same system that recharges the batteries of a Toyota Prius or Tesla Model S when the driver hit the brakes.
The rate at which energy is stored or recovered can vary, too, depending on the speed and quantity of the railcars. Overall, the concept is comparable to pumped hydro, but it uses weights and railcars instead of water. “Those are very old [and proven] concepts,” says Robert Armstrong, director of the MIT Energy Initiative, confirms.
AERS isn’t alone. “There’s a bunch of people who have been trying to use the fact that heavy stuff up in the air is a lot of storage potential energy to balance supply and demand in electricity markets,” says Baker. Energy Cache had a similar idea, though the company never moved beyond a small pilot project. Its “gravel on ski lifts” idea, as backer Bill Gates called it, was a system of buckets that would pick up gravel at the bottom of a hill then haul it to the top. When the grid called for energy, the buckets would pick the gravel up and let gravity move it back down the hill, powering an electrical generator as it went. Another company, Charroux, France-based Sink Float Solutions, is developing a system that would move concrete weights up and down the 13,000 feet of depth that lies between the ocean’s surface and floor.
Today, about 97% of the world’s energy storage is provided by pumped hydro plants, but Francesca Cava, vice president of operations at ARES, thinks that there’s room for rail energy storage, With a smaller footprint than a pumped hydro plant, no fossil fuels or emissions, and claimed higher reliability, rail energy storage could complement bigger pumped hydro systems in some areas and stand in for them in others.
The very first commercial-scale rail energy storage plant was approved in Nevada, and ARES should begin construction later this year, Cava says. “It will take about 18 months to complete, test, and become operational once construction commences.” The company is planning to lay a 5.5 mile track up an 8˚ slope, along which the rail cars would typically move at less than 20 miles per hour. Seven 8,600-ton trains will be set on the tracks, and each train will be equipped with two locomotives and four railcars. ARES estimates its project cost to be somewhere around $55 million.
It could easily scale up, Cava says. “We are easily expanded by building multiple or longer rails. In fact, scaling larger is even more economical, since the base costs are already paid for and you are simply adding either more rails or trains.” Rail storage also doesn’t have the same cycle limitations that batteries face, though since it is a mechanical system, it’s subject to regular maintenance and wear and tear.
However, with only one concrete proposal in the works, the future of rail energy storage isn’t settled. And in the meantime, venture capital firms like Khosla Ventures are betting on yet another technology.
Up the Pacific coast from the ARES headquarters, in northern California, is an up-and-coming company called LightSail Energy. Founded by two physicists in 2009, this startup is pursuing an energy storage system that relies on industrial-sized tanks to hold pressurized air. LightSail recently shipped their very first tanks to their customers.
Like pumped hydro, compressed air isn’t a new technology. For decades, two facilities have been forcing air into underground caverns and recovering the energy later as it streams out through a turbine. Pacific Gas and Electric Company operates them both, using hollowed out salt formations in Alabama and in Germany.
Compressed air energy storage can be a relatively simple technology, but in the more basic implementations, efficiency can suffer. Compressing air generates heat, and unless that heat can be captured, the entire system may recoup as little 27%. But LightSail captures that heat by spraying water into the compressor. That water is then either stored for later use, perhaps by warming the compressed air to give it more oomph, or to heat nearby buildings.
Compressed air—particularly in a modular format like that of Light Sail’s—shows promise, but it isn’t widely used yet. “Often times, energy storage technologies—especially the newer ones which have not been proven or are still in the developmental phases or are emerging—have not been fully demonstrated,” Sakti says. “So you don’t know how much they’re going to cost.”
That hasn’t stopped other teams from pushing compressed air’s potential. RICAS2020, for example, is a design study that’s investigating other ways to improve compressed air’s efficiency. Instead of spraying the compressed air with water, RICAS2020 sends the air through a chamber of crushed rock. The large surface area allows the rocks to acts a heat exchanger, absorbing heat from the air before it hits the storage chamber. When the air is let out, it again passes through crushed rock, reclaiming the heat to give it more energy to turn the turbine. The team is hoping the entire system can recover 70–80% of the stored energy.
Batteries and Beyond
With the total solar eclipse that’s expected to darken the skies from Oregon to South Carolina later this year, American solar companies may find themselves in a position similar to that of the Germans two years ago. Grid managers will need take careful measures to prepare for the first eclipse of the 21st century.
With the spread of renewable energy generation and storage technologies, it looks like these concerns are only going to become more common. California may be better prepared than most. While the state has been pushing for more energy storage—to support their renewable energy target of 50% by 2030—the move to storage accelerated in the wake of the Aliso Canyon gas leak that was discovered in Southern California in October 2015. The second largest gas storage facility in the U.S., Aliso Canyon provided natural gas to homes, businesses, and 10,000 MW of power plants. The shutdown of those plants threatened rolling blackouts, so over the summer of 2016, the utility and the state fast-tracked new storage installations.
Storage got another boost in October 2016 when Jerry Brown, governor of California, signed into law four bills providing $249 million to prod utilities into adding another 500 MW of storage. That’s in addition to the 2020 target of 1,325 MW that’s already on the books. Together, the goals will help the state make the most of its nearly 5 GW of solar power capacity.
In recent months, utility companies have been adding storage by the tens of megawatts. Most of them have been large banks of lithium ion batteries, but there’s nothing in the law to prevent other systems from being installed.
California, like elsewhere, has discovered that cleaner alternatives like solar and wind energy can provide a substantial fraction of the electricity, but they’ve also realized that it’s wise to have a plan for a rainy day.