ComEd launched a pilot project to test the use of battery energy storagetechnology to reduce the impact of power outages in residential areas where customers experience service interruptions, particularly in extreme weather events.

ComEd’s Community Energy Storage pilot is being conducted in Beecher, Ill., about 40 miles south of Chicago. The pilot will focus on improving power reliability for customers experiencing multiple interruptions.

One of the first utilities in the nation to install CES, ComEd will also evaluate the potential of this technology to serve as a proactive tool to drive continuous improvement in service reliability.

“Through grid modernization and smart grid investments, our reliability performance has been best on record for five years running, and we’re committed to continuous improvement,” said Michelle Blaise, senior vice president, Technical Services, ComEd. “We want all ComEd customers to experience great reliability and that’s why we’re innovating and piloting emerging technologies such as energy storage to bring new value to communities and help improve service for our customers. We’re excited about the potential that battery storage offers to minimize the impact of a power outage while we continue to make progress in preventing them.”

ComEd is using the PureWave Community Energy Storage system from Chicago-based S&C Electric Co. Featuring a 25kWh lithium-ion battery, the CES unit was installed near the existing ComEd equipment that provides power to the homes of Beecher customers selected for the pilot. In the event of a power outage, the energy storage system will automatically restore power and has enough capacity to supply power to a group of customers for the duration of most typical outages. The momentary power outage when the battery storage takes over is barely perceptible while crews take the precautions needed to ensure a safe and seamless return-to-normal.

Blaise said that additional CES pilots are planned for the ComEd service territory. ComEd is also exploring the potential of energy storage to support the integration of renewable energy sources. The company received a $4 million grant from the Department of Energy to develop and test a system that integrates solar and battery storage with a microgrid, which is a small energy grid that can power a local, defined area in times of emergency.

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AGL has commissioned the first phase of what it claims is the world’s largest virtual power plant (VPP).

The project, in Adelaide, South Australia will be ramped up in three stage with 1000 Sunverge batteries installed across the city. The total storage capacity will reach 5MW/7MWh.

The AU$20 million (US$15.4 million) trial is one of a number of measures being undertaken to improve the security of the electricity network in South Australia. The state has been hit by price shocks and blackouts with extreme weather, reliance on one interconnection and even the large volume of renewables blamed for the problems.

“The VPP will deliver benefits for multiple groups, including: customers by reducing their energy bills; the network by lowering required capital investment to upgrade infrastructure; for AGL by providing another source of generation to deploy into the network with the balance used in our portfolio; and, the environment through reduced emissions,” said Andy Vesey, managing director and CEO, AGL.

According to the utility, customers taking part in the trial will save AU$500 a year.

Sunverge is also participating in an ARENA-backed VPP trial in Queensland.

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Of all the great initiatives that came out of South Australia’s energy plan on Tuesday, one thing doesn’t appear to make sense: why spend so much money on a peaking gas generator when storage options are clearly cheaper?

The big question was over these two sums: The $360 million in government monies set aside for a 250MW gas plant that might rarely be switched on, and the $20 million that treasurer Tom Koutsantonis says could be enough to get a 100MW battery storage facility built by the private sector before summer.

Surely, analysts and pundits say, spending more on battery storage is going to give a bigger and more immediate bang for the buck than the gas generator. And they won’t become a redundant asset as the gas peaker threatens to be in as little as five years time.

In theory, those sums suggest, South Australia could cause some 1.8GW of battery storage to be built for the same taxpayer funds as a gas generator. Of course, it is much, much more complex than that.

The reality is that the $150 million set aside in the new Renewable Technology Fund is probably going to support more battery storage than can be sustained under current market rules. (Indeed, some of it is earmarked for solar thermal, pumped hydro or even hydrogen).

Battery storage – in current market rules – will trade only on energy market volatility and the arbitrage between high and low prices (fill it up with cheap excess wind and solar and sell it at high, peak demand prices).

The more storage that is added, then the less volatile the market will become, and the less money that can be made.

So storage will probably not be fully economic and widespread until the overall market rules are changed and battery storage technologies can access its multiple value streams.

This will come from rule changes such as dumping the 30 minute settlement in favour of a 5 minute settlement, and the introduction of a new ancillary service market, and maybe for grid augmentation.

Then there will be nothing stopping it, although longer-dated storage such as solar thermal, pumped hydro or even hydrogen will also be needed at various points in the transition to 100 per cent renewable energy.

But it is the volatility that the South Australia government wants to kill as soon as it can. The state has always had a volatile electricity market, courtesy of its stringy network, daytime manufacturing and high air con use.

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Flow batteries have made strides recently in bringing down costs and improving efficiencies, but they are going to have a tough time competing with the entrenched market leader: lithium-ion batteries.

More than half of the 1,280 MWh of worldwide battery installations on the power grid since 2010 have been li-ion batteries, according to Department of Energy data. Looking at just 2015 and 2016, that share rises to 60%. In the United States, li-ion has an even bigger market share at 78% since 2010 and 97% since 2015.

By comparison, sodium-based batteries comprise about 30% of the worldwide grid storage market and flow batteries just 7%.

But it seems that just about every other week, researchers announce advances they say will make flow batteries cheaper, safer and more competitive when stacked up against li-ion batteries.

Theoretically flow batteries would be the logical choice for utility-scale grid applications. Flow batteries exchange negatively and positively charged fluids to produce electrical current. There is also relatively little degradation of the fluids, giving them longer charge-discharge cycles and longer life spans. They can also be scaled to match growing needs relatively by increasing the amount of fluid in the tanks.

But some of the disadvantages for flow batteries include expensive fluids that are also corrosive or toxic, and the balance of system costs are relatively high along with the parasitic (on-site) load needed to power the pumps.

The market leader in flow battery chemistry is vanadium, but researchers are working on other chemistries to bring down costs and improve the safety and environmental profile of flow batteries.

Just last month, researchers at Harvard University said they had developed an aqueous organic and organometallic redox flow battery that uses a neutral, non-corrosive liquid. And researchers at the universities of Michigan and Utah last month said they have found a way using computer modeling to devise a flow battery anolyte that is 1,000 times more stable than existing compounds.

Researchers are also tweaking less exotic compounds, such as derivatives of a chemical based on vitamin B2, in an effort to improve flow battery chemistry.

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In Chile’s last auction for power, SolarReserve bid a world-record-breaking low price at just 6.3 cents per kWh ($63/MWh) for dispatchable 24-hour solar.

SolarReserve’s CSP technology with integrated thermal storage provides 24-hour solar power, and is ideally suited for Chile’s grid with round-the-clock power needs due to its huge mining industry. To bid 24-hour solar at 6.3 cents per kWh is a world record for CSP (Concentrated Solar Power), a form of solar utilizing heat from the sun that can be stored thermally. Chile has open auctions for both fossil energy and renewables, and no subsidies.

SK: You bid Crescent Dunes in Nevada at 13.5 cents, then Redstone in South Africa at 12 cents. Your bid in Chile was 6.3 cents. How are you able to come down so low for solar that includes thermal storage so it can be dispatched any time — 24-hour solar for just 6.3 cents/kWh? 

KS: SolarReserve has made substantial advances in our technology that has increased efficiencies and brought down capital costs since our first project in Nevada.

But there are a number of other factors that influence power prices and the Chilean market appears to be ideally suited for solar thermal with storage. In addition to the best solar resource in the world, the country’s stable financial status along with US dollar denominated power contracts results in excellent financing and investment terms

Interestingly, our thermal solar bids were lower than all but one new-build natural gas project bid into the last tender. Chile has no indigenous fuels, so natural gas needs to be imported in the form of LNG, which is much more expensive than natural gas costs in the US, and is susceptible to spikes in supply pricing in the world markets.

SK: How do you ensure that you can deliver solar power around the clock? Does that require operating at something less than full capacity? [Background explainer: How CSP works: CSP with integrated thermal storage makes solar dispatchable at any hour 24 hours a day.]

KS: Our bulk storage capabilities utilizing molten salt give us tremendous flexibility, without having to consider the degradation issues associated with batteries or the replacement cost issues.

We’re designing the projects in Chile for full capacity 24 hours a day. To do that we put in about 14 hours of storage. That will give us the full capacity of the project essentially 24 hours a day.

We could design it for three times the power for 8 hours a day or twice the output for 12 hours a day, but since Chile’s load is really a 24-hour load we design the storage to handle that.

It really comes down to the design of the steam cycle and turbine capacity, the storage tank capacity, and the size of the heliostat field, which dictates how much additional power you can store when its sunny.

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The biggest natural gas leak in U.S. history led to a boom in large-scale energy-storage systems, the technology that’s long considered the elusive link to integrating solar and wind power into electric grids.

U.S. homes and businesses — primarily utilities — installed storage systems with 336 megawatt-hours of capacity in 2016, double the amount from the previous year, according to a study released Tuesday by GTM Research and the Energy Storage Association. That’s about enough batteries to power a city the size of San Diego for an hour.

The majority of the installments came during the last three months of the year, as Sempra Energy’s San Diego Gas & Electric Co. and Edison International’s Southern California Edison turned to powerful batteries to make up for anticipated electricity shortfalls stemming from the Aliso Canyon gas leak. The result is that California, which has a goal to install 1.3 gigawatts worth of batteries by 2020, now has more energy storage capacity than any other region of the U.S.

“The fourth quarter marked a turning point,” Ravi Manghani, GTM Research’s director of energy storage, said in a statement. “California will play a significant role in the future as utilities there continue to contract energy storage.”

Longer Charges

Developers have installed 643 megawatts of energy-storage projects in the U.S. since 2010, according to Bloomberg New Energy Finance. The increase comes as power companies struggle to incorporate energy from wind and solar farms, where production ebbs and flows based on unpredictable breezes and sunshine.

Revenue from the U.S. energy-storage market will grow fivefold, from $664 million this year to $3.3 billion in 2022, according to GTM, a Boston-based market renewable-energy research company.

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A £10.8m project on the Isles of Scilly will test how electric vehicles (EVs) and domestic batteries can integrate into low-carbon energy systems that reduce electricity costs and promote the use of renewables.

UK-based smart battery developers Moixa Technologies will integrate platforms for EVs and batteries into an Internet of Things-based (IoT) energy resource management system developed by Hitachi to balance the supply and demand of electricity on the islands as part of the Smart Energy Islands (SEI) project.

Moixa’s chief technology officer Chris Wright said: “Moixa’s role in the SEI project will demonstrate how ordinary people will play a key role in our future energy system. Home batteries and electric vehicles controlled by smart software will help create a reliable, cost-effective, low-carbon energy system that will deliver savings to homeowners and the community.

“Our systems will support the reduction of fuel poverty on the Scilly Isles and support their path to full energy independence. They will be scalable and flexible so they can be replicated easily to allow communities all over the world to cut carbon and benefit from the smart power revolution.”

Although the project, which is backed by an £8.6m investment form the European Regional Development Fund, will not fund EVs and charging points, it will optimise how the batteries in these vehicles can be teamed with learning algorithms to support the energy use of the consumers and balance electricity needs across the islands.

Moixa hopes that the SEI project will develop systems that can be replicated globally, and for the islands it will concentrate on reaching 2025 goals to cut electricity bills by 40%, source 40% of energy demand from renewables and create a 40% share on the transport market for low-emission vehicles – currently there are 1,253 vehicles on the island.

The Isles of Scilly is located 28 miles from the UK mainland and the 2,200 islanders have to import fossil fuels and electricity to meet needs due to a lack of inland gas supply. As a result, 22% of households are affected by fuel poverty.

Moixa and Hitachi hope that the energy management systems will improve fuel standards and increase the share of renewables in the energy mix, which currently sits at 270KW. The SEI project will aim to double this output by installing solar systems at 100 homes – a tenth of the housing stock for the isles – and two 50Kw solar gardens will be developed.

Energy management systems will be installed in the homes fitted with solar and 190 businesses in the area will be fitted with energy monitoring devices. Ten buildings will also test additional smart energy systems such as batteries and air source heat pumps.

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While Germany is one of the world’s leaders in solar PV and now an early leader in residential energy storage, utility-scale energy storage is still “under discussion” and not yet a mature proposition, industry figures have said.

“The German market as far as I know is pretty much mature when it comes to residential, when it comes to utility-scale and C&I (commercial and industrial) however, to me it is still a lack of regulations and policies which [stop the market from maturing],” Dario Ciccio, global application manager for energy storage systems at global technology group ABB, told Energy-Storage.News at the Energy Storage Europe conference and exhibition in Dusseldorf.

About 50,000 residential energy storage systems have been sold in Germany in the last four years, with ABB among those showcasing a residential product at the show this week, a scalable inverter and 2kWh battery that can be configured to fit three units for a total of 6kWh, allowing households with PV systems to maximise their onsite self-consumption. Germany’s high installed base of residential PV has made it a hotbed for modest but steady growth in the home storage market. The show, which in previous years had appeared to be heavily weighted towards utility-scale solutions, featured a large number of domestic makers of residential systems, such as Solutronic and E3DC which are not heavily promoting their products outside Germany as yet.

ABB was also showcasing an energy storage inverter which can be scaled from 1MW to 100MW but Ciccio said that interest for very large storage systems seemed to be more intense from regions that included the UK, California, Texas and the PJM Interconnection market in the US and regions of Asia such as China, Korea and Japan than from Germany. While Germany has seen a number of high profile pilot projects go online at utility-scale, Ciccio said this interest appeared to have slowed, with outsiders as yet not keen to risk their money on storage at scale.

“We see that there were some major projects in Germany [that] some utilities did, today we see that it’s not really moving fast [as a sector]. The utility-scale projects are very slow, from what I see now,” Cicio said.

“The Energiewende (Germany’s ‘energy transition’) to me is still somehow… investors, are still afraid to make the investment if there is no good balance to move in this direction.”

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With the ability to control generation and load, storage becomes one of the most critical assets in the utility portfolio. The results of incorrectly assembling disparate components from multiple vendors into a single solution could result in potentially dangerous and expensive failures.  As the industry begins to scale and multi-megawatt sites are deployed in just a few short months—expertise in software, system integration, design, construction, grid integration and ongoing management and maintenance are the critical factors for success. 

Download this complimentary white paper today to learn about best practices in designing and deploying the next-generation of intelligent energy storage solutions.

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It’s a PR pitch too good to be true.

A global battery giant launches two new products in Australia, declaring one of those products could be the solution to a power crisis engulfing South Australia.

Within 48 hours, the global tech guru chief executive of said battery company pledges on social media to deliver a solution in 100 days, or provide it for free.

Social media goes nuts, as social media does. And before long, it seems South Australia’s unreliable power problems might be solved via a trans-Pacific Twitter deal between billionaires.

Politicians scramble for Elon Musk’s number, eager not to miss the opportunity to genuflect before a global tech deity with more Twitter followers than they could ever hope to match.

But before we all get carried away, it’s worth pointing out that Tesla’s fix for SA’s power problems probably won’t eventuate. Here’s why.

Tesla isn’t the only company proposing a battery fix

They don’t have the celebrity figurehead of Elon Musk, but there are already several companies proposing big battery solutions for South Australia. And some of their proposals are already well advanced.

Zen Energy, chaired by the Rudd government’s carbon-pricing tsar Ross Garnaut, has been working on plans for a battery storage of up to 150 megawatts (MW) at Port Augusta.

Lyon Solar wants to build 200-250 MW of large-scale batteries in several projects around the state.

And that’s just the start.

Tesla is late to the party

The South Australian Government has already dangled a sizable carrot to the power market to try to encourage both a new source of electricity generation and a new source of dispatchable renewable energy.

Last year, it issued a tender for supply of 75 per cent of the Government’s own electricity usage for a new market entrant, and another for the remaining 25 per cent to come from dispatchable renewables (batteries or another storage solution).

Those tenders have since closed, which means if the Government were to field offers from a new player — say Tesla — it could run into probity problems.

There is money for storage options from the Federal Government currently on the table, via the Australian Renewable Energy Agency.

But that brings us to the next problem.

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