A California-based company, Advanced Rail Energy Storage (ARES), is providing grid-scale energy storage using small electric locomotives, according to a March 4 report by Interesting Engineering. And there is a system ready to go online in Nevada soon.

During off-peak hours, when energy draw is low, the company uses rail cars to push heavy concrete blocks to the top of an incline using excess power generated from distributed energy resource. To release the energy from storage, when demand is higher on peak, the company allows the cars to roll back down the slope – using gravity to generate power through their regenerative braking systems, IE said.

ARES claims that the system can respond to increase and decreases in demand in seconds. The company also has said that the system boasts charge/discharge efficiencies of 80 percent and can deliver constant power for periods of up to eight hours.

ARES conducted a pilot system test in Tehachapi, California, a city in the Tehachapi Mountains, sited at an elevation of nearly 4,000 feet. During the test, the rail cars were motored up and rolled down a 268-meter (0.16-mile) track.

After the concept was successfully tested, ARES obtained permission to construct the grid energy system in Nevada. The fleet of automated 300-ton electric traction drive shuttle trains is due for completion anytime soon, the news outlet said.

When they are in service, the shuttles will travel up and down a 7.2 percent grade slope and should provide 50 MW of rapid response power to help stabilize the Californian electrical grid supply.

The system will comprise 34 shuttle units and will operate on a combined 9.2-km (5.7-mile) track with elevation differences from top to bottom of 640 meters (0.4 miles).

ARES CEO Jim Kelly said that the new system can “be deployed at around half the cost of other available storage technologies. Just as important, ARES produces no emissions, burns no fuel, requires no water, does not use environmentally troublesome materials and sits very lightly on the land.”

This platform is highly scalable, according to the company – with small installations of 100-MW with 200 MWh storage capacity up to large 2-GW to 3-GW systems with 16 GWh to 24 GWh storage capacities.

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German energy giant E.ON is continuing its push into the US energy storage market with a new deal for two projects in Texas.

The Texas Waves energy storage projects will see E.ON construct two batteries with a total storage volume of nearly 20 MW. They will be located at E.ON’s existing wind parks in Pyron and Inadale in the west of the state.

Both projects are expected to be operational by the end of this year, when they will each provide 9.9 MW of energy to the grid.

The batteries will provide system services for the Electric Reliability Council of Texas (ERCOT) market, balance out fluctuations across the grid, and improve supply security. The lithium-ion battery systems connected to the grid will be an integral component of the E.ON wind parks near Roscoe and will be charged by the wind turbines there.

For the Texas Wave projects, E.ON is collaborating with Virginia-based Greensmith Energy, a provider of energy storage software and services in which E.ON has invested since 2015.

Greensmith is also a partner in Iron Horse, E.ON’s first grid-connected battery project located southeast of Tucson, Arizona. This 10 MW energy storage system, which includes a neighbouring 2 MW solar plant, will come online in the first half of this year.

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Lithium-ion (Li-ion) batteries will continue to dominate the stationary energy storage sector, according to Lux Research.

The dominance is not total, however. Lux found that a new approach, current generation flow battery technology, “has an economic case for certain very large and long-duration applications.”

The press release on the study says that Li-ion has lowered “levelized” cost of storage (LCOS) for the majority of system sizes and durations. However, space requirements are leading to greater costs at higher scales. That is creating an opportunity for flow battery technology, according to research analyst Tim Grejtak, who wrote the report.

The release offered some numbers to buttress the main finding that Li-ion is dominant:

Li-ion beats the most popular vanadium-based flow battery technology on LCOS due to higher round-trip efficiency (83% vs. 65%). Li-ion also dominates the application space from 75 kW to 100 MW, and from 15 minutes of storage to eight hours, with costs above $0.37/kWh.

The study also suggests that new technology, such as Lockheed Martin’s metal complex chemistry that is expected to be available next year, will change the economics of the sector and that diversification is a good approach as prices fall.

Apparently, the thought that li-ion batteries are not optimal for large implementations is not universal. Power Magazine last month showcased a 30 MW, 120 MWh system that was put into service by San Diego Gas & Electric. It is, according to the story, the largest li-ion battery in the world.

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Led by a record-breaking fourth quarter, energy storage deployments in the United States totaled 336 megawatt-hours in 2016, doubling the megawatt-hours deployed in 2015. According to GTM Research and the Energy Storage Association’s U.S Energy Storage Monitor 2016 Year in Review report, 230 megawatt-hours came on-line in the fourth quarter of the year, more than the sum of the previous 12 quarters combined.

Aquion Energy, a rising star among manufacturers of large-scale energy storage systems, announced on Wednesday it had filed for Chapter 11 bankruptcy reorganization amid struggles with fundraising from investors.

The company said it is in search of a buyer and hopes to emerge from bankruptcy “in the coming weeks.” It has laid off about 80 percent of its personnel, keeping only a core research and development team. The company has halted its factory operations in Westmoreland County and paused marketing and sales efforts, it said in a release.

“Creating a new electrochemistry and an associated battery platform at commercial scale is extremely complex, time-consuming, and very capital intensive,” read a statement jointly attributed to Scott Pearson, Aquion’s outgoing chief executive officer, and Suzanne Roski, a managing director at Protiviti, a Virginia-based consulting firm.

Ms. Roski was named Aquion Energy’s chief restructuring officer during the bankruptcy.

The statement continued, “Despite our best efforts to fund the company and continue to fuel our growth, the company has been unable to raise the growth capital needed to continue operating as a going concern.” Aquion could not be reached for comment beyond its statement.

The bankruptcy filing comes as the Lawrenceville-based manufacturer of sodium-ion batteries had apparently found success in deploying its technology. It generated hype and awards for its innovation, attracting investors along the way.

Aquion Energy had been spun out from Carnegie Mellon University in 2009 by Jay Whitacre, a CMU professor of materials science and engineering, attracting funding from venture capital firm Kleiner Perkins Caufield & Byers.

The year before, Mr. Whitacre had produced the first functioning aqueous hybrid ion battery, which the company has been producing since summer 2011. Aquion has been shipping its batteries commercially since mid-2014, according to its website.

Batteries like Aquion’s are considered the “holy grail” for widespread renewable energy development because they can store large amounts of energy for use during times when it is not easily produced — such as when the sun is not shining or when the wind is not blowing.

Aquion received many awards from energy and technology trade groups, and frequently shared its progress and thoughts on the battery market.

It was listed as one of the Massachusetts Institute of Technology’s Top 100 Smartest Companies in 2015 and 2016, as well as picking up an award in 2015 from a German organization supporting the energy storage industry.

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The United Kingdom is on the cusp of an energy crisis. A recent study by the Institution of Mechanical Engineers (IMechE) claimed that increasing usage, the loss of coal and the closure of nuclear power stations could lead electricity demand to exceed supply by 40–55 percent by 2025.

Hopes have been pinned on the power of renewable energy to address the gap, but without dramatically improved storage options, it will remain incapable of supporting the maximum levels of demand.

Powervault offers a solution. The intelligent home battery is designed to automatically store solar and off-peak grid electricity, ready to be unleashed whenever it’s needed.

The powerplay

Powervault CEO Joe Warren first encountered the challenges of energy consumption at the beginning his career in the internet sector in the 1990s, where he had to ensure there was enough electricity to keep tens of thousands of computers running. Warren has been working in what he calls the “smart grid sector” for about ten years, investigating new ways of managing electricity on the network.

“About five years ago I realised that we were deploying so much wind and solar energy that we really needed to find some way of storing it so we could use it when we needed it,” he says.

“That’s because a lot of wind energy and a certain amount of solar energy effectively ends up being wasted because it’s not needed at the time it’s generated.”

He discovered that storage system at Powervault in 2014. The company developed a consumer battery device and appliance for homeowners that stores low-cost solar electricity without having to buy it from the centralised grid. Later that year, Powervault launched the first plug-and-play energy storage device.

Inside the Powervault cube are a collection of power electronics to make the energy usable, a monitoring system to check energy is being generated or consumed, control electronics that determine when to charge or discharge, and batteries to power it.

“If you’re generating electricity and that’s going back onto the grid, it charges up the batteries,” says Warren. “And conversely, if you’re consuming electricity then it will discharge the batteries to reduce your electricity bill.

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A staggering 230 MW/h of energy storage systems were installed in the last three months of 2016, more than the previous 12 quarters combined.

That strong finish put the total amount of energy storage systems installed in 2016 at 336 MW/h, or 100 percent over 2015 according to GTM Research and a report by the Energy Storage Association.

The U.S. energy storage market is now estimated to reach 7.3 GW in 2022, representing an investment of $3.3 billion.  

Ravi Manghani, GTM Research’s director of energy storage, said the huge amount of fourth-quarter installations was due to a burst of deployments with a very short development time.

And that burst could continue, thanks to California.

“California will play a significant role in the future as utilities there continue to contract energy storage under the state’s 1.3-gigawatt mandate,” he said. “While California took over the pole position in 2016 from PJM, the market shift was also transformational in terms of applications — from short-duration ancillary services to longer-duration capacity needs.”

Currently, 88 percent of all installed energy storage capacity in the fourth quarter was delivered within California.

Matt Roberts, executive director of the Energy Storage Association, said much of the development was done to address the gas leak at Aliso Canyon, as well as the development of new applications and business models.

“The energy storage industry is rapidly maturing, and in 2016 we saw that growth take hold in a significant way,” he said.

Utility-scale storage consisted of most of the deployed MW/h, though commercial and residential systems provided 25 percent of the total. Most of that was from commercial storage in California, though two-thirds of residential deployment were outside California and Hawaii.

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Energy storage trains are a fantastic idea to save energy. Energy grids supplied by renewable energy sources naturally benefit from energy storage of any kind. “Pumped” hydropower is one of the common “go to” solution for energy storage. As we are sure you are aware, water energy storage uses electricity off peak to pump water.  This more “traditional” method pumps water to higher elevations to take advantage of the power of gravity to power turbines downslope.

For instance, the Taum Sauk Hydroelectric Power Station, Missouri works exclusively using pumped storage hydropower. Yeah, “pumped” hydropower is great but a little dull. Why can’t we replace water with something interesting, like say mini trains? That would be amazing, right?

Have we got your attention? Great, let’s take a closer look at ARES’ simple solution to energy storage.

Energy storage trains: Mini trains? Tell me more

A California-based company, Advanced Rail Energy Storage (ARES) have done just that. Their innovative land-based alternative to the “traditional” hydro-pumped storage method provides grid-scale energy storage using cute little trains.

These small electric locomotives use rail cars to push heavy concrete blocks to the top of an incline using excess power generated from renewable energy plants. As you’d expect, excess power is utilized during off-peak hours when grid draw-off is low. To release energy, when demand is higher on peak, you simply let the train roll back down the slope. The trains, under the influence of gravity, generate power through their regenerative braking systems, which is cool.

ARES claims that the system can respond to increase and decreases in demand in seconds. They also claim the system boasts charge/discharge efficiencies of 80 percent and can deliver constant power for periods of up to eight hours. Not too shabby. The energy might otherwise be wasted.

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Pumped storage is a decades-old technology with a relatively simple concept: When electricity is cheap and plentiful, use it to pump water up into a reservoir above a turbine, and when electricity is scarce and expensive, send that pumped water down through a turbine to generate more power. Often, these pumped storage facilities are auxiliary to other electricity-generating systems, and they serve to smooth out fluctuations in the amount of power on the grid.

A German research institute has spent years trying to tailor pumped storage to ocean environments. Recently, the institute completed a successful four-week pilot test using a hollow concrete sphere that it placed on the bottom of Lake Constance, a body of water at the foot of the Alps. The sphere has a diameter of three meters and contains a pump and a turbine. Much like traditional pumped storage, when electricity is cheap, water can be pumped out of the sphere, and when it’s scarce, water can be let into the sphere to move the turbine and generate electricity.

The Fraunhofer Institute for Wind Energy and Energy Systems Engineering envisions spheres with inner diameters of 30m, placed 700m (or about 2,300 ft) underwater. Assuming the spheres would be fitted with existing 5 MW turbines that could function at that depth, the researchers estimate that each sphere would offer 20 MWh of storage with four hours discharge time.

In an underwater “energy park,” dozens of these spheres could be connected near an offshore wind farm to create a system that would be able to add extra reliability to a renewable-heavy grid. The institute admits that the economics of this project only work on a large scale. It estimates that more than 80 spheres would be needed “to achieve a relevant overall performance/capacity for the energy market.”

In November, the Fraunhofer Institute placed the test sphere 200m off the coast of Lake Constance and 100m under the lake’s surface. The institute just retrieved its sphere last week. Researchers are still sifting through the data gleaned by the pilot program in order to create better computer models on how this scheme would work in the real world. The institute wrote that it wants to conduct a follow-up project using a larger sphere that would be underwater for a longer time.

According to the institute’s press release, a sea-based project is still three-to-five years out, but industrial partners and public sponsors are apparently interested in financing the project further. This test was completed with help from Germany’s Federal Ministry of Economics and Technology.

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