GE and longtime customer Southern California Edison announced a plan to install a battery storage and gas turbine hybrid.

The two-project solution first calls for installation of a battery energy storage system from Current, powered by GE, followed by upgrades to a GE LM6000 gas turbine to integrate the two systems.

The LM6000 Hybrid EGT, which is scheduled to be deployed at two SCE sites in the coming months, was developed in response to changing regulations and grid requirements in the wake of California’s Aliso Canyon energy crisis earlier this year and will ultimately support increasing renewable energy capacity on the California grid.

The solution, which will qualify for California’s Independent System Operator’s tariff for contingency reserve, answers a critical need for Southern California, where regulations on natural gas usage and storage are changing in the wake of the state’s Aliso Canyon energy crisis earlier this year. GE’s Power Services and Current businesses worked to develop the joint solution in a competitive offer in collaboration with Wellhead Power Solutions, LLC.

The LM6000 Hybrid EGT product integrates a 10 MW battery energy storage system from Current and an existing GE LM6000 aeroderivative gas turbine with control system upgrades provided by GE’s Power Services. The system will allow the turbine to operate in standby mode without using fuel and enable immediate response to changing energy dispatch needs. By eliminating the need to constantly run the turbines at minimum loads to maintain spinning reserves, the LM6000 Hybrid EGT will save fuel, reduce maintenance costs and cut down on greenhouse gas emissions.

The LM6000 Hybrid EGT offers ancillary and grid support at a lower cost and smaller GHG footprint than traditional resources, plus it can provide 50 MW of GHG-free spinning reserve, flexible capacity, and peaking energy; 25 MW of high-quality regulation; and 10 MVA of reactive voltage support and primary frequency response when not online.

The battery energy storage system is expected to be installed and operational by the end of 2016, and the updated and integrated turbine controls are scheduled to be operational in early 2017.

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The UK is a key market for Tesla’s Powerwall and Powerpack energy storage products, and Tesla is seeing demand for additional installations of its commercial oriented products after the first Powerpack install was completed last month.

Tesla is exhibiting at Solar Energy UK|Clean Energy Live this week. This is the first exhibition in Europe where the company is demonstrating its three key products – Powerwall, Powerpack and its electric vehicle range.

The UK was the third market globally to receive Tesla Energy products after the US and Australia due to the high level of interest expressed when the Powerwall and Powerpack products where launched in 2015.

Tesla has been accrediting installers to its programme since the turn of the year and has increased its base to several hundred. It said it intends to increase this number in the coming months with the right partners to provide customers great service and technology.

Although the first Tesla Powerpack install in Europe was completed by Camborne Energy Storage to provide services to the grid, Tesla sees a product benefit when stacking this with other applications such as peak-shaving, that enables commercial and industrial customers to reduce their exposure to peak energy prices.

While there had been early doubts surrounding the potential for commercial energy storage solutions, particularly at the start of the year, the UK market is appearing to embrace the technology. Earlier this summer supermarket chain Sainsbury’s revealed it was testing an energy storage application in one of its stores with a view to a wider roll-out in the near future.

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If Massachusetts acts on recommendations in the recently released report from the state’s Department of Energy Resources (DOER), the state could have a mandate for 600 MW of energy storage by July of next year. 

The DOER is in the process of forming a stakeholder group to discuss the details of what a storage mandate would look like, with a year-end 2016 target date for setting out its recommendations. If a mandate is approved, it would be put in place by July 12, 2017 with a target date of 2020.

However, the State of Charge report goes beyond the possible creation of an energy storage mandate and recommends a list of programs and projects, as well as policy changes that would facilitate the integration of energy storage into every aspect of the state’s grid. 

The report used tools from Alevo Analytics to model the state’s electric system and found that the total optimal amount of advanced energy storage would be 1,766 MW. “Advanced” storage in the report does not include pumped storage, though it was included in the simulations. Massachusetts has about 1,600 MW of pumped storage capacity.

The modeling showed that adding up to 1,766 MW of advanced energy storage would maximize Massachusetts’ ratepayer benefits to the tune of $2.3 billion. That would yield a benefit-cost ratio ranging from 1.7 to 2.4 for ratepayers. In addition to benefits for ratepayers, the modeling results also shows the potential for $1.1 billion in direct benefits to resource owners from market revenue.

The report identifies benefits from a range of functions that storage can provide, including energy cost reductions, reduced peak capacity, ancillary services cost reductions, transmission and distribution cost reductions and a greater ability to integrate renewable resources into the grid.

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Over the past several years, FERC has been actively engaged in trying to integrate energy storage into the operation of wholesale power markets.

Starting in 2011 with Order 755, FERC made room for fast responding resources like batteries in wholesale markets, and followed in 2013 with Order 784, which directed wholesale market operators to find ways to compensate fast response resources.

FERC’s announcement of a technical conference to look into storage issues in regional wholesale markets follows itsnotice in April seeking inputs from grid operators on barriers that might exist in those markets for energy storage resources.

The technical conference will examine how well storage resources fit into existing categories and if changes need to be made to better accommodate storage, which can perform services that can variously appear as supply or demand, sometimes simultaneously.

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The nascent energy storage sector is often described in terms of how fast it’s currently expanding — and its potential for explosive growth in the near future.

But across San Diego County decades-old deployments such as ice storage are still in use just as cutting-edge technologies such as lithium-ion storage grab so many headlines.

At the sprawling Mission City office complex in Mission Valley not far from Qualcomm Stadium, 29 ice thermal storage tanks help slash the energy costs for the owners of three office towers who retro-fitted the facility in 1999.

“San Diego has had a long history with different types of ice storage technology,” said Brian Bloker, an account manager for commercial systems at Trane air conditioning. “Some people know there is ice storage technology that’s been in operation for the past 20 years and other people say, hey, I didn’t know this was here.”

It’s easy to miss the the Mission Valley facility. After all, it’s below ground, under a parking garage.

“It kind of operates quietly in the background,” Bloker said. “But the technology itself has not changed.”

The ice tanks are fed by two 320-ton chillers that send an antifreeze solution called glycol through tubing that freezes the water in the tanks, turning it into ice. The process typically runs at night when practically no employees are in the office.

During the day, the process is reversed, essentially providing cooling for the office building and acting in a sense as a battery for a building’s air conditioning system.

It’s an example of what is called “load-shifting,” in which large blocks of energy loads are moved until the power supply system can more easily handle them  — something energy storage is especially well designed to tackle.

The payoff for the building owners comes from running the system at night when utility prices are significantly lower than they are during peak hours during the day.

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There are now 35 standalone grid-scale projects and at least 1,500 residential energy storage units in operation, industry analysis finds

The analysis also reported at least 453MW of new projects are planned or in development, while an additional 200MW of enhanced frequency response services have recently been contracted by the National Grid.

In addition, the industry reported that “multiple gigawatts” of proposed storage projects were planned but have not yet had the final go-ahead. The pipeline includes much of the 1.2GW of projects that were pre-accredited ahead of the recent National Grid auction, meaning they have already demonstrated they are ready to deploy and have secured planning permission and grid connection capacity.

The report said “anecdotal” reports the REA collected indicate there have been tens of GW worth of applications for storage to the distribution network, although this may not all have planning and grid permission.

The REA is now calling for a better policy framework to be put in place to unlock this fast-expanding market. James Court, head of policy and external affairs at the REA, said with many technologies having quickly advanced to reach commercial scale, the storage industry is not seeking a direct subsidy. But he warned the lack of a joined-up and supportive policy framework remains the “single greatest barrier” to the industry’s growth.

“Storage is already a reality for the UK and right now there’s an opportunity to cement us as a global centre for investment, deployment, and research,” he said. “Storage is a critical technology for the decentralisation of the UK’s energy system and will support long-term renewables deployment.”

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Australians are no longer able to count on revenue generated from excess solar energy feeding into the grid, so they are turning to energy storage solutions to keep excess energy for themselves.

Falling by the wayside, Australia’s household solar feed-in tariff (FIT) schemes have entered their first wave of drastic reductions as around 63,000 households in South Australia feel the first pinch. [Disclosure: This is a sponsored post from Australian Solar Quotes.]

By the end of 2016, over 275,000 solar homeowners in South Australia, Victoria, and New South Wales will see their solar feed-in tariffs dropping by as much as 90 percent.

Declining FITs are Promoting Demand for Energy Storage

In September, South Australia’s FIT fell from AU$0.16/kWh to a minimum required payment of AU$0.068/kWh. Also by the new year, 67,000 solar homes in Victoria will see tariffs and net metering programs falling from AU$0.25/kWh to AU$0.05/kWh.

The biggest drop will hit around 146,000 solar customers in New South Wales. On 1 January 2017, current FITs from AU$0.60 to AU$0.20/kWh in New South Wales will fall to between AU$0.055 and AU$0.072.

Australian Solar Quotes (ASQ) CEO Darryn Van Hout notes that the previously generous FITs enabled many solar consumers to learn the basics of solar energy and PV technology.Scrapping the tariffs, says Darryn, has further promoted demand for energy storage systems.

“It’s definitely a trigger point for most consumers to look at this new technology,” says Van Hout. ASQ reports that it has seen “an increase in demand for quotes for storage batteries from buyers looking to save thousands of dollars on their bills, with the Australian market seeing around 300 homes come together to buy storage batteries at discounted rates.”

Van Hout adds, “many of the customers approaching ASQ have been solar customers coming off the New South Wales solar bonus scheme.”

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Amber Kinetics, the flywheel energy storage startup, has landed a project with Hawaiian Electric, a utility that’s looking for all kinds of distributed energy resources to make solar and wind an integral part of its grid.

It’s the first project outside of California for the Union City, Calif.-based company, albeit a small one — a single Gen2 Model 25 steel flywheel system at the Campbell generating station, one of the two big power plants that keep Oahu’s grid energized.

Hawaiian Electric will be testing the 25 kilowatt-hour unit to evaluate how it stands up against a long list of energy storage projects it has underway. These range from utility-scale batteries, to distributed projects, like Stem’s megawatt of behind-the-meter batteries in commercial buildings, or the grid-responsive water heaters being installed in homes across the island.

Amber Kinetics burst onto the scene late last year with a 20-megawatt, 80 megawatt-hour contract with Pacific Gas & Electric, but it’s been developing its technology for years now. That work has included testing in the Bay Area, as well as in Hawaii, where it’s been a partner of the state’s Energy Excelerator green tech incubator since 2013.

The startup’s main claim to fame is its multi-hour energy storage duration — a rarity for a technology better known for delivering huge bursts of power over short timeframes. That’s mainly because spinning heavy disks or cylinders can pack a lot of punch, but tend to lose long-term storage potential through friction.

We’ve seen a handful of utility-scale flywheel projects built, such as the Beacon Power 20-megawatt installation in upstate New York. But they’ve exclusively been used for fast-responding, short-duration grid services, like frequency regulation.

Amber Kinetics says it has surmounted the barriers to long-lasting kinetic energy storage, with a combination of better design, more homogeneous steel disks to reduce friction, and the latest super-efficient electric motors and power electronics. The units can “support unlimited cycling with zero capacity loss over a 20-year-plus service life,” according to the company.

That puts its technology into the running against electrochemical batteries like lithium-ion or metal-oxide flow batteries for a broader set of utility needs. In the case of its PG&E project, Amber Kinetics is expected to supply up to four hours of energy per day during times when the system is facing peak demand for electricity.

Hawaiian Electric hasn’t specified just how it plans to test its new flywheel, but it certainly has a need for energy storage to help it manage its growing share of solar and wind power. Nearly one in 10 homes on Oahu have solar panels, and large-scale wind farms are being built with batteries to help integrate their on-again, off-again energy into the grid.

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Four bills signed by California governor Brown will mandate a distributed energy storage procurement, fund incentives for behind-the-meter storage, and more.

On Monday, California Governor Jerry Brown signed four bills that will support and mandate expanded deployment of energy storage in California. This includes adding $83  million in annual funding to the Self Generation Incentive Program (SGIP) and requiring that California utilities procure up to 500 MW of distributed energy storage.

AB 1637 increases SGIP funding by a total of $249 million over the next three years, and follows on a recent decision by the California Public Utilities Commission to assign 75% of the SGIP budget to energy storage.

AB 2868 requires California’s three investor-owned utilities to file applications for new programs that will involve procuring up to 500 MW of distributed energy storage. This is in addition to the 1.325 GW energy storage target set by AB 2514 in 2013, under which procurement has already begun.

A key consideration here is that while AB 2514 included a set-aside for distributed storage, the majority of procurements under the mandate have been from large battery systems on the bulk transmission system.

A third bill, AB 2861 takes aim at interconnection barriers, and authorizes CPUC to create an expedited resolution process for behind-the-meter energy resources including storage which are seeking interconnection.

Finally, AB 33 directs the California Public Utilities Commission and the California Energy Commission to study the potential for long-duration bulk energy storage, such as pumped hydro storage.

California Energy Storage Alliance (CESA) applauded the four bills. “CESA is proud to have played a key role in these bills, which further enable energy storage to become a valued piece of the mainstream energy toolkit, mitigate unwarranted market or interconnection barriers, and allow bulk storage technologies to be appreciated as a solution to renewables integration,” said CESA Executive Director Janice Lin.

The new bills follow on a wave of policy wins for energy storage, including Massachusetts passing a bill to mandate that utilities procure energy storage in August, and New York City announcing a 2020 goal to install 100 MWh of energy storage last Friday.

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Research by a German team could aid the superconductor industry by improving capacitance by an order of magnitude compared to current approaches. The researchers identified the improvement when using a “hybrid mix” of potassium ferricyanide in aqueous media.

In a paper titled “High-Performance Hybrid Energy Storage with Potassium Ferricyanide Redox Electrolyte,” the team from the Leibniz Institute for New Materials (INM) in Saarbrücken also described how they overcame current leakage with an ion-exchange membrane.

The team, led by Professor Volker Presser of INM’s Energy Materials program division, found the hybrid medium had an energy capacity of 28.3 watt-hours per kilogram, or 11.4 watt-hours per liter.

This nears the 30-watt-hours-per-kilogram upper limit for current supercapacitor products and is “higher compared to the same cell operated in aqueous sodium sulfate,” said the team. 

The researchers also noted “excellent long-term stability” across 10,000 charge and discharge cycles. “This hybrid electrochemical energy storage system is believed to find a strong foothold in future advanced energy storage applications,” concluded the study’s authors. 

Lu Zhang, a scientist at Argonne National Laboratory in the U.S., said the redox electrolyte was a “key aspect” of the research. “This ferricyanide redox electrolyte can provide a higher capacity, [delivering] higher power out of the devices with this chemistry,” he said. 

“Another important finding is the ion-selective membrane. That is another key component to maintain the capacitance here, preventing the cell’s discharge, which would lead to the degradation of the capacitance,” said Zhang.

He said the research could be used to build supercapacitors that would last longer in a steady state without discharging: “You don’t want self-discharge happening. When you charge the capacitors, you want the energy holding there for as long as possible.” 

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