Digital industrial company GE and flexible energy storage systems operator Arenko Group have entered into a strategic alliance to build grid-scale energy storage systemsin the UK.

The companies will seek to leverage the advantages of combining GE‘s battery technology solutions, power electronics and advanced controls with Arenko’s leadership in operating batteries in the UK market and its proprietary energy trading software platform.

GE Power global commercial and marketing executive Mirko Mollnari stated that energy storage would help balance supply and demand close to real time, avoiding frequency drifts and supporting the mid-term response to grid imbalances.

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Startup Gravitricity, which has just received a £650,000 grant from Innovate UK, plans to use abandoned shafts to house massive weights. When energy is plentiful, the weights will be winched towards the surface, in much the same way that water is driven uphill in pumped hydro storage. However, unlike pumped hydro, the system should be able to respond to fluctuations in demand almost instantly.

“As we rely more and more on renewable energy, there is an increasing need to find ways to store that energy – so we can produce quick bursts of power exactly when it is needed,” said Gravitricity managing director Charlie Blair.

“So far there is a lot of focus on batteries, but our idea is quite different. Gravitricity uses a heavy weight – up to 2000 tonnes – suspended in a deep shaft by cables attached to winches. When there is excess electricity, for example on a windy day, the weight is winched to the top of the shaft ready to generate power.”

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Tesla has been making big moves on the energy storage market in Australia, but they are now all being dwarfed by this new project that will see them install solar arrays and Powerwalls on 50,000 homes to create the biggest virtual power plant in the world.

The company’s main project has been the 100MW/ 129MWh Powerpack project in South Australia, the largest in the world for now.

But now instead of being a large centralized battery system using Tesla’s Powerpacks, the new project announced today is using Tesla’s residential battery system, the Powerwall, to create decentralized energy storage, which basically results in creating a massive virtual power plant.

South Australia Premier Jay Weatherill announced the deal today – the biggest of its kind by far.

The 50,000 homes in the state will be fitted with 5 kW solar arrays and 13.5 kWh Tesla Powerwall 2 battery systems.

It will result in at least 650 MWh of energy storage capacity distributed in the state.

Tesla said in a statement:

“When the South Australian Government invited submissions for innovation in renewables and storage, Tesla’s proposal to create a virtual power plant with 250 megawatts of solar energy and 650 megawatt hours of battery storage was successful. A virtual power plant utilises Tesla Powerwall batteries to store energy collectively from thousands of homes with solar panels. At key moments, the virtual power plant could provide as much capacity as a large gas turbine or coal power plant.”

It will function much like Tesla’s giant Powerpack system, which charges when demand and electricity rates are low and discharges when demand and prices are high.

We reported last month the single battery system managed to make around $1 million in just a few days.

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Tesla is partnering with South Australia’s Labor government to create the world’s largest virtual power plant, consisting of 50,000 homes fitted with solar panels and the company’s Powerwall 2 home battery unit. The $800 million project will have roughly six times more energy storage capacity than Tesla’s massive Powerpack farm at the Hornsdale wind farm near Jamestown.

Initial plans for the virtual grid would begin with low-income, social housing properties, with each house being equipped with a 5 kW rooftop solar system and a 13.5 kWh Tesla Powerwall 2 home battery system. In total, the project is expected to deliver 250 MW of solar energy and 650 MWh of battery storage capacity when complete, while providing grid stability by shifting demand away from a stressed grid during peak hours.

State premier Jay Weatherill expressed his excitement about the virtual power plant that would not only complement Tesla’s big battery project at the Hornsdale wind farm; it would dwarf the 100MW/129MWh Powerpack system many times over as well.

“My government has already delivered the world’s biggest battery, and now we will deliver the world’s largest virtual power plant. We will use people’s homes as a way to generate energy for the South Australian grid, with participating households benefiting with significant savings in their energy bills. Our energy plan means that we are leading the world in renewable energy and now we are making it easier for more homes to become self-sufficient,” he said, according to a RenewEnergy report.

To fund the creation of the world’s largest virtual power plant, the State Government is assisting the release of a $2 million grant and $30 million loan from the Renewable Technology Fund to get the project underway, as noted in the project’s official website. The SA government is also seeking additional funding from private investors. Tesla would be responsible for the installation of the solar systems and Powerwall 2 home battery packs.

Smart Energy Council CEO John Grimes lauded Tesla and the South Australian government for the initiative. Grimes, for one, noted that the construction of the virtual power plant would place the country at the forefront of the green revolution in technology.

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Carbon-free energy: Is the answer blowing in the wind? Perhaps, but the wind doesn’t always blow, nor does the sun always shine. The energy generated by wind and solar power is intermittent, meaning that the generated electricity goes up and down according to the weather.

But the output from the electricity grid must be controllable to match the second-by-second changing demand from consumers. So the intermittency of wind and solar power is an operational challenge for the electricity system.

Energy storage is a widely acknowledged solution to the problem of intermittent renewables. The idea is that storage charges up when the wind is blowing, or the sun is shining, then discharges later when the energy is needed. Storage for the grid can be a chemical battery like those we use in electronic devices, but it can also take the form of pumping water up a hill to a reservoir and generating electricity when letting it flow back down, or storing and discharging compressed air in an underground cavern.

Motivated by a view that storage is a “green” technology, governments are increasingly promoting utility-scale and distributed energy storage. For example, in November 2017, New York Gov. Andrew Cuomo signed a bill mandating targets for storage adoption by 2030. Other states with similar policies are Oregon, Massachusetts, California and Maryland. Companies like Tesla also have been branding storage systems as clean technologies.

But do large storage systems lower emissions in our current grids? In a recent study, we found this isn’t necessarily the case – a reflection of how complex the electricity system can be.

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The first large-scale commercial plant was built in Huntorf in Germany and has now been in successful operation for many years.

The reason for the slow progress of CAES is the prohibitive cost of a suitable storage vessel. Large CAES schemes have relied on disused underground caverns to provide a reservoir for the compressed air, but these are not readily available and may not be close to a market for electrical energy.

Also, existing CAES plants are not environmentally “green”. Compression of air into the storage reservoir generally relies on compressor power generated by fossil fuel, and recovery of stored energy uses conventional gas turbines burning fossil fuel.

Even if the compressor power is provided by wind turbines, the plant is predominately fossil fuel-powered.

Fresh opportunities

The prospects for CAES could be about to change. Buoyant supports for offshore wind turbines are of increasing interest.

Floating foundations such as the Statoil Hywind type require a substantial buoyancy volume for hydrodynamic stability and this offers an obvious opportunity for storing energy as compressed air.

Figure 1 (below) shows the dimensions of an articulated buoyant column sized for a 6MW turbine in 80m water depth.

Figure 2 (beneath) shows the buoyant column diameters required to achieve sufficient stability for turbines mounted on such columns as a function of turbine power and water depth.

Figure 3 (bottom) shows the total energy that could be theoretically stored in these columns when filled with compressed air at 10 bar.

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In a paper published in Chemical Science, an open access journal of the Royal Society of Chemistry, researchers in the lab of Ellen Matson, assistant professor of chemistry, describe modifying a metal-oxide cluster, which has promising electroactive properties, so that it is nearly twice as effective as the unmodified cluster for electrochemical energy storage in a redox flow battery.

The cluster was first developed in the lab of German chemist Johann Spandl, and studied for its magnetic properties. Tests conducted by VanGelder showed that the compound could store charge in a redox flow battery, “but was not as stable as we had hoped.”

The key to a redox flow battery is finding chemicals that can not only “carry” sufficient charge, but also be stored without degrading for long periods, thereby maximizing power generation and minimizing the costs of replenishing the system.

By making what Matson describes as “a simple molecular modification”— replacing the compound’s methanol-derived methoxide groups with ethanol-based ethoxide ligands—the team was able to expand the potential window during which the cluster was stable, doubling the amount of electrical energy that could be stored in the battery.

 “The straightforward, efficient synthesis of this system is a totally new direction in charge-carrier development that, we believe, will set a new standard in the field,” said Matson.

The electrochemical testing required for this study involved equipment and techniques not previously used in the Matson lab. Hence the collaboration with Timothy Cook, assistant professor of chemistry at the University of Buffalo, and Anjula Kosswattaarachchi, a fourth-year graduate student in the Cook lab. VanGelder visited the Cook lab for training on testing equipment, and in turn helped Kosswattaarachchi with synthesizing compounds.

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In 2017, utility-scale energy storage moved from a handful of experimental programs to front-page news, with prominent deployments in Australia, Texas, Southern California, and hurricane-ravaged Puerto Rico. Building on these successful installations, 2018 should be an even more important milestone for energy storage, as policymakers encourage electricity system operators to include storage in their integrated planning. Regulators will also need to clarify the market rules around energy storage, to allow utilities and other storage operators to “stack” ancillary services on top of storage, as the California Public Utilities Commission (CPUC) recently did.

Energy storage will affect the entire electricity value chain as it replaces peaking plans, alters future transmission and distribution (T&D) investments, reduces intermittency of renewables, restructures power markets and helps to digitize the electricity ecosystem. For utilities, battery storage will become an integral tool for managing peak loads, regulating voltage and frequency, ensuring reliability from renewable generation, and creating a more flexible transmission and distribution system. For their customers, storage can be a tool for reducing costs related to peak energy demand.

Driving all of this opportunity is the decreasing cost of battery storage, a factor largely of the rapid increase in their development and manufacture of batteries for electric vehicles. Research by Bain & Company estimates that by 2025 large-scale battery storage could be cost competitive with peaking plants—and that is based only on cost, without any of the added value we expect companies and utilities to generate from storage. In some markets, renewables combined with battery storage already cost less than coal generation.

Utilities and their large commercial customers are also looking at ways to create more value around their investments in storage, to make deployments more feasible. It’s these stacked services that the CPUC recently addressed in a set of clarifying rules meant to deal with the ambiguity around battery storage. In addition to using batteries to store electricity during periods of low demand and then releasing those stored electrons during peak periods to shave peak loads, stored electricity can provide services like voltage and frequency modulation. And it can ensure greater reliability from intermittent renewable generation.

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Arizona’s utility regulator, Andy Tobin, proposed a new energy modernization plan which will update Arizona’s policies on clean energy, storage, biomass, efficiency, vehicles and more.

The sweeping plant, seems to be an intelligent look at the most modern techniques, combined with pragmatic decision-making – to clean a power grid.

Currently, Arizona has a 15% renewable energy mandate by 2025, a goal which has already been met. This new proposal will see that increase to 80% by 2050, “with the ultimate goal of being 100%.” Nuclear power is included in the clean energy target.

For energy storage, a new target of 3GW by 2030 will be set per the original reporting on the topic by Utility Dive. The proposal cites:

“Low priced, and sometimes free electricity, is being exported from surrounding states; at the same time, increasing peak demand in Arizona is causing new expensive investments for ratepayers.”

The smartest thing I’ve ever heard someone do is taking advantage of ‘free stuff.’ California has paid Arizona take electricity in the past.

This 3GW of storage target is the largest volume target so far, California is second at 2GW – however – California’s number is by 2020. If we compute the targets on a per capita basis – Arizona has 6.9 million people versus California’s 39.2 million – we’d have to see California reaching 17GW of energy storage by 2030.

Bloomberg suggests the USA will have about 75GW of energy storage by 2030 – California has a habit of leading the country, and I expect California to blow past 17GW by then – possibly being as much as (or far more depending on doubling pace) 37.5GW (50% of US total).

Technologies that qualify as energy storage include: electrochemical (batteries), mechanical (flywheels/compressed air), thermal (molten salt), and gravitational (pumped hydro).

The proposal sets a target of 90 MW of biomass generated from the ‘treatment’ of 50,000 forests by the end of 2021. Only “high-risk fuel,” sourced 80% from within Arizona, will qualify toward the 90 MW of required biomass energy production.

In another example of renewables coming for gas peaker plants – Arizona’s new proposal includes a new “Clean Peak Standard”, where utilities will be required to use renewable resources during peak hours – with the logic that it’ll drive energy storage construction.

These renewable fed energy storage plants, simply by existing on the network, will probably also offer ancillary services like the Australia 100MW/129MWh Tesla Battery, but it will also be requested to do something much bigger – eating the ‘duck curves’ that arise as a result of growing daytime solar power production.

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