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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A 3,000MW energy storage target, proposed in Arizona as part of a grid modernisation policy, recognises the role of the technology in reducing the need for fossil fuels to stabilise the grid, a consultant has said.

Yesterday, Andy Tobin of the state’s regulator, the Corporation Commission, presented a plan that includes a goal to generate 80% of Arizona’s power from renewable sources by 2050, a commitment to review the existing Renewable Energy Standard and Tariff (REST) policy, to use renewables to mitigate peaks establishing a ‘Clean Peak’ standard and to deploy 3,000MW of energy storage to “leverage low priced energy during the day”.

The Commission will vote on the proposal in the next couple of weeks. A final vote is expected which would make the regulatory proposal legally binding, within six months to a year, Lon Huber, vice president and head of consulting at Stratagen Consulting, told Energy-Storage.News.

The 3GW target would be the biggest established to date in the US – the first state to set a target, California, is calling for 1.35GW by 2024 and New York for 1.5GW by 2025. While the timeline for deployment is longer for Arizona than those two previous title-holders, Huber pointed out that relative to the state’s size, the figure pencils out at a far higher capacity deployed per capita than in the others.

Lon Huber said the establishment of the target is closely linked to known plans for development of new gas turbine facilities by Arizona’s major utilities, including Arizona Public Service, which is projecting that it will need 5GW of new gas plants by 2032. Huber said it was likely the 3,000MW figure was arrived at as “a fraction of the new combustion turbines in the IRP (Integrated Resource Plans) of the utilities”.

“I think the assessment of what could be cost-effective storage was probably based on the need for new peakers over the next 15 years, more than anything. I think the innovation here is that, depending on different states and how they do things, you could end up in a situation where you buy a lot of renewables but you still need a large fossil backup fleet.”

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The CEO of Orsted, the world’s largest offshore wind developer, has said that his company is working to establish “a scalable commercial model” for solar PV and energy storage, viewing both as potential drivers of long-term growth.  

Danish power company Orsted, formerly known as DONG Energy until a rebrand and restructuring last year that also included selling off its oil and gas businesses, has just reported its latest quarterly financial results, including reporting for the full 2017 year.

For 2017, the group saw DKK22.5 billion (US$3.77 billion) operating profit, an increase of 18% from the year before. This included a 74% rise in profits from its wind business. The company made an overall net profit of DKK13.3 billion (US$2.23 billion), an increase of more than DKK1 billion from 2016.

The report and accompanying statements from the company and CEO Henrik Poulsen reiterated Orsted’s commitment to a transition to a low carbon, green and sustainable energy system repeatedly. The company is aiming to go coal-free by 2023 and also to source 95% of its heat and power generation from renewables by that time.

“Our strategy is based on the vision of an integrated green energy system, where renewable energy technologies can be combined with each other and with energy storage solutions, more flexible and intelligent patterns of consumption and electrification of the transport sector, heating systems and industry,” Poulsen said.

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Marking its entrance into the Japanese battery market, and gearing up to take advantage of the growing self-consumption opportunities in the country, London-based Moixa Energy Holdings Ltd has entered into a partnership with one of Japan’s largest trading houses.

Under the exclusive marketing deal, Itochu has said it will install Moixa’s GridShare platform as a standard, on its products by this summer. Overall, Itochu also aims to sell more than 6,000 units of its “Smart star” home battery systems, which were developed in cooperation with the NF Corporation, by the end of this March.

AI technology

Under the GridShare aggregation platform, Moixa uses AI technology to trade excess power stored in smart batteries owned by partners in the GridShare scheme, with the National Grid. This helps to reduce the load on grids during peak demand, to create a flat grid.

The partners receive a share of the profits in return, the amount of which depends on whether the partner has a fixed income or profit share membership.

“The technology will save customers money by using artificial intelligence to optimise the performance of their battery based on their patterns of behaviour, the weather conditions and market prices,” said Moixa in a statement released.

Expansion

In addition to the distribution partnership, Itochu has said it will invest £5 million (around US$7.1 million) in Moixa to support international expansion.

This follows on from an investment of £500,000 by Japan’s Tokyo Electric Power Company Holdings (TEPCO) last April. Overall, the company raised around £3.5 million in 2017. It is specifically eyeing the European and U.S. markets for expansion.

“Moixa will now seek to expand its GridShare partnerships with Japanese utilities and electric vehicle manufacturers and to market services to electricity networks. It is also planning trials in the US and Europe this year,” read the statement.

In the U.K., the company has already installed nearly 1,000 battery systems. It further holds patents in the U.K., U.S. and Australia on distributed smart battery systems, and aggregating batteries for grid services.

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Battery technology engineer Ernest Villanueva—who has helped design the battery models powering all of Tesla’s models—has left the electric vehicle maker, CNBC reports, citing a person familiar with the matter.

Mr. Villanueva’s LinkedIn profile still states that he is Manager of Battery Module Design at Tesla Motors. He has worked at Tesla since 2006 at various roles in battery module design.

According to CNBC, Villanueva holds eight patents and is credited with the design of the battery modules for all Tesla vehicles. Tesla declined comment for CNBC, while Villanueva did not immediately respond to requests for comment.

If Villanueva’s departure is confirmed, it would be yet another senior manager at Tesla who has left the EV carmaker over the course of several months.

Earlier this month, Uber hired Tesla’s lead battery expert Celina Mikolajczak as Director of Engineering and Energy Storage Systems to work on the ride-hail company’s ‘flying car’ project.

Also this month, another two senior engineers at Tesla were reported to have left the company—Jason Mendez and Will McColl, Jalopnik reported two weeks ago. McColl confirmed he had left Tesla, saying “I’m continually inspired by my colleagues’ resolve, and I wish them strength as they ramp and refine Model 3. It’s an amazing car!”

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States in the Pacific Northwest are moving forward with policies encouraging new energy storage projects, but the region already has a lot of old fashioned storage — the type that sits behind a dam.

Hydropower provides the region with a cheap and abundant source of renewable energy that can also be used, in some instances, to store energy; and that presents a challenge for newer technologies, such as lithium ion batteries.

“Policy is pushing energy storage in the Pacific Northwest, but the economics of storage could have an uphill battle against the economics of hydropower,” said Jay Paidipati, a director at Navigant Consulting.

In a new report, consulting firm Cadmus Group says energy storage development in the Pacific Northwest is stymied by the lack of a compelling business case, policies and pricing structures that favor large power plant development over distributed energy resources, sluggish movement towards grid resiliency planning, and potential concerns about storage technology lifetimes.

The Northwest does not have an organized capacity market, which means that storage cannot be traded with clear price signals. The region also lacks differential pricing that recognizes the locational and temporal flexibility of storage. That severely limits two possible revenue sources for a potential battery storage project: the sale of ancillary services and the opportunities that high electricity prices create for price arbitrage.

The Cadmus report, which takes a broad look at energy storage in the Northwest, also notes that there are many balancing authorities in the region, but there is no mechanism to easily aggregate and transfer storage resources across them. That engenders a need for complex bilateral agreements that make collaboration more difficult.

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Arizona is setting out to prove clean energy leadership doesn’t exist solely in coastal states like California and New York.

Andrew Tobin, a member of the Arizona Corporation Commission, proposed a clean energy overhaul Tuesday that would put the state at the front of the pack. The Energy Modernization Plan aims to produce one of the cleanest energy mixes in the nation, while lowering prices for consumers and improving grid reliability.

That means not only tackling the issue of clean baseload power, but also figuring out how to supply peak power in a cost-effective and clean way. Peak hours drive increasing expenses for utilities and their customers, a challenge that intermittent wind and solar alone cannot address. As such, Tobin’s plan includes an 80 percent clean energy target by 2050 coupled with a 3,000-megawatt energy storage procurement target for 2030.

That would leapfrog the state ahead of California and New York, which have dominated the grid modernization discussion so far. They both have 50 percent renewable energy targets on the books for 2030, and storage targets of 1,300 megawatts and 1,500 megawatts, respectively.

“We’re not trying to get on the train; we’re trying to be the engine in the train,” Tobin told GTM. “This is Western people doing things and setting lofty goals and reaching them.”

He has asked to get the concept on the agenda for the ACC’s meeting on February 6. If the five-member commission adopts the plan, as Tobin hopes it will, staff would begin a rulemaking to finalize the official language. That process could take up to a year and would involve stakeholder input.

Time for an update

The state currently is working toward a 15 percent renewable portfolio standard for 2025. The ACC set that policy in 2006, and included a 30 percent carve-out for distributed generation starting in 2012.

Since that time, solar generation has expanded, but so have the other tools available for sophisticated grid planning. That means it’s time for an update, starting with the name. Tobin suggests switching from the “Renewable Energy Standard and Tariff” to the “Clean Resource Energy Standard and Tariff.”

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