A new redox flow battery demonstration project was launched in Belfast, Northern Ireland, this week.

The joint UK-Ireland research programme will assess the best electrochemical properties of a redox flow system for the Irish grid, develop a pilot model and identify a path for a >125kW “scalable unit”.

The ImpRESS project was launched at an International Energy Research Centre (IERC) workshop at Queen’s University, Belfast.

“Ireland has fluctuating energy dynamics, and as a consequence of being an island, the scale of the power system is such that it provides an excellent test-bed for the evaluation of energy storage solutions,” said Professor Tony Day, executive director of the IERC.

“The ImpRESS project focuses on all-island electrical energy generation, consumption and storage to meet current requirements, and examines technologies for future electrical networks and grids. It will deliver engineering recommendations capable of influencing future grid-code standards and electrical power system policy development,” said Day.

Ireland is adding more renewables to its grid as it struggles to meet its 2020 renewable energy target of 20%.

“The ImpRESS project provides new commercial opportunities for the businesses involved, including energy trading, providing access to new ancillary services for I-SEM, single energy market pricing and a competitive advantage for faster response services,” said Dr. Matthew Kennedy, head of strategy and business with the IERC.

The project involves collaboration with Chinese vanadium redox flow battery manufacturer Rongke Power, which is in the process of developing and then building a vast 200MW / 800MWh flow battery installation in China’s Dalian peninsula. A 125kW test site with supply from multiple renewable energy sources will be developed at the Belfast site.

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Hawaiian Electric Co. (HECO) has big plans for energy storage, but is wary of moving too quickly. The utility is looking for better storage technology and economics before moving too much on deployment.

The island state is often considered a test case or laboratory for the integration of renewable energy. With a 100% renewable portfolio standard in Hawaii and a 2045 target date, the state’s main utility is quite focused on what its generation mix is going to be and how it is going to get there.

The utility is expecting 2,700 MW of energy storage on Oahu by 2030, said Colton Ching, senior vice president for planning and technology at HECO. That includes both customer sited, behind-the-meter batteries and utility-scale energy storage installations, either owned by the utility or competitively bid to a third party. But HECO has been slow to embrace energy storage, despite the rapid influx of solar power in the state.

Hawaii has the highest solar penetration of any state. There are already 80,000 rooftops with solar panels and HECO expects that number to double by 2030. But so far, the utility has only 3 MW of utility-scale storage projects, and all three of those were pilot projects.

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Reality is, that most people who want solar power on their home actually want energy storage as well. We want energy storage because if the grid goes down, we want our house to run smoothly – day or not, sunny or cloudy. Additionally, many of us hold onto the dream of disconnecting from The Man.

At SolarPower International 2017 it was clear that the solar+energy storage hardware market – SolarEdge, Sonnen, BYD, Kehua, Outback, Hauwei, Schneider and others – are almost ready (or in terms of Sonnen/SolarEdge/Schneider – ready today) to serve the home energy demands of the broader population.

First, a small bit of education. The large majority of solar power installations installed today need special wiring/extra hardware in order to keep pumping electricity into the house when the grid goes down – this is due to ‘anti-islanding‘ laws. It’s probable that your solar system will also shut down when the grid goes down. This will change.

Outback and Schneider are the old-time players in the off-grid solar market that I’m most familiar with. The Outback FlexPower is a respected package of hardware (first image on the left below). Personally, my favorite installation was of a Schneider system I developed for a close friend at their off-grid cabin in the western hills of the Rocky Mountains (four images to the right below – including their pool). These systems offer all of the wonders of modern life – including the aforementioned pool.

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A new study by Navigant Research indicates annual installations of utility-scale power storage for transmission and distribution deferral is expected to grow rapidly over the next decade.

Specifically, installations are expected to grow from 331.7 MW this year to 14,324.8 MW in 2026.

“The major advantage energy storage has compared to conventional T&D upgrades results from the flexibility related to how storage systems can be deployed and the variety of services they can provide,” said Alex Eller, research analyst with Navigant Research. “Unlike most grid infrastructure systems, ESSs can be deployed in small, modular increments as needed to serve growing demand with limited risk of oversizing or stranding assets.”

Navigant predicts utility companies will turn to these types of deployments to avoid the typical challenges associated with transmission, including community concerns, timelines and future load growth uncertainty. 

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California is on the cusp of a dramatic jump in deploying cost-saving, climate-solving technology in the form of customer-sited energy storage, but the industry needs help cutting red tape that keeps the cost of the technology unnecessarily high for customers.

Energy storage helps electricity customers and the electric grid in many ways: It reduces monthly bills; delivers grid services such as peak reduction, emergency backup and smoothing out the increasing share of renewable energy production; and it enables California to keep the lights on while reaching our clean energy goals.

The state has recently passed a number of policies that could deploy thousands of energy storage projects in the next several years, such as the Self-Generation Incentive Program, storage and renewable energy procurement targets for each of the investor-owned utilities (IOUs), and the AB 2868 authority given to IOUs to accelerate widespread deployment of energy storage.   

But most California cities and counties — less experienced with the new technology and the relevant codes and standards — issue permits for energy storage projects in inconsistent processes with a broad range of permit fees.

Developers spend a great deal of time with repeated travel to deliver materials in person, to submit “wet stamps” on minor revisions of plans, and to complete reviews by unrelated agencies — all of which drive up installation costs for the customer. 

Moreover, local jurisdictions are largely unaware that the storage industry and fire protection professionals have collaborated on a comprehensive forthcoming 2018 standard for energy storage fire safety, the NFPA 855, as well as a wealth of product safety standards.

A new bill to clarify good permitting practices and to make permits and related fees more consistent was signed by Governor Jerry Brown September 30. 

The fact that the bill, AB 546, passed unanimously with bipartisan support shows policymakers’ clear intent to give customers access to this valuable new technology and to arm cities and counties with clear information on how best to permit energy storage projects.

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This summer, Massachusetts became the third state to set an energy storage target. It is not mandatory, and the 200 MWh target was lower than some observers expected, but it still put the Bay State at the top of states encouraging energy storage.

Massachusetts is now continuing to push forward with energy storage, setting up an inquiry into the eligibility of energy storage for net metering benefits. Net metering is a popular policy mechanism that compensates distributed generation for excess energy sent to the grid — usually at the retail rate. Net metering policies vary by state and can include larger projects than typically found on residential rooftops. 

However, the policy is silent on the role of energy storage when paired with net-metered systems, like rooftop solar. 

But stakeholders are seeking to define energy storage’s role, with Massachusetts taking that first step. In part, the inquiry grew out of a petition filed by Tesla in May 2017, seeking a ruling on the eligibility of solar power systems paired with energy storage devices to receive net metering benefits. Last month, the DPU issued a “limited scope” advisory opinion, only applicable to Tesla, that small-scale battery storage and solar systems should be eligible for net metering. 

State regulators will now take up that issue holistically in this inquiry.

The inquiry will also review the current standards and procedures that electric distribution companies use to bid the capacity from certain net metering facilities into ISO-New England’s FCM, and how they use FCM revenues to offset the cost of net metering services.

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Elon Musk didn’t need 100 days after obtaining a connection agreement to switch on the Tesla big battery in South Australia. In fact, it took him less than 100 minutes.

That’s how quickly the battery was up and running after the ink dried on the connection deal with the state’s transmission company ElectraNet last Friday.

By the early evening, some 300 Tesla Powerpacks already in place were delivering all the power for the unveiling event, stored from the adjoining Hornsdale wind farm, a three-hour drive north of Adelaide.

Of course, it’s not all in place yet. About half is installed – 30MW/65MWh out of 100MW/129MWh it has contracted to build – and it has yet to fully engage with the grid.

But it has only taken two months since Tesla won a South Australia government tender to get this far, and despite some hints that a demonstration was in the wind, the 500 or so invited guests were stunned by what they saw.

“So much has been done in an incredibly short period of time,” Musk said at the unveiling on Friday night. “Talk is cheap, action is difficult … but this is not just talk, this is reality.”

And, Musk noted – ominously enough for the fossil fuel interests looking on from afar – this is just the start of what he expects will be a rapid transition to renewables.

“The vast majority of the world is still fossil fuel powered and this is really just the beginning. But what this serves as is a great example to the rest of the world of what can be done.”

Talking to some of the energy market officials, developers, and investors at the event, it seems clear that battery storage installations like this will mushroom across Australia in coming years.

Some are already well flagged: Neoen, which owns and will operate the South Australia big battery, plans another 20MW/34MWh storage facility at the yet-to-be-built Bulgana wind farm in Victoria, there is another 30MW/8MWh facility to be built at the Wattle Point wind farm, not to mention the 250MW big battery proposed by AGL to replace the ageing and decrepit Liddell coal generator.

There is also a smaller battery at the soon to be opened Lakeland solar farm in north Queensland, batteries at the Kennedy solar, wind complex also in north Queensland, pumped hydro at the Kidston solar farm, and dozens of other storage project.

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Green Charge, a subsidiary of ENGIE, announced plans to develop and operate whats being called the largest utility-scale energy storage system in Massachusetts.

The three-MW system will be installed at the 5.76-MW Mt. Tom Solar, which began operations in January adjacent to the former Mt. Tom Power Station, and will deliver energy to Holyoke Gas & Electric. ENGIE expects the system to be complete by April 2018.

The system will be used to optimize intermittent solar energy and reduce utility capacity costs for HG&E while reducing stress on the HG&E distribution system and improving power quality and reliability.

As part of Massachusetts’ Peak Demand Management Program, HG&E was awarded a $475,000 MA Department of Energy Resources Grant to contract with, schedule, measure, and analyze the energy storage system. UMass Amherst will quantify the peak reduction value to the distribution system, accounting for equipment value, cost reduction potential, and overall project data. The goal of the grant is to provide research and recommendations on the future distribution system value of battery storage devices throughout the state.

“Massachusetts is proud to be a national leader in energy efficiency programs that reduce overall consumption and we are committed to continuing our work to improve energy costs disproportionately affected by times of peak demand,” said Massachusetts Governor Charlie Baker. “The demonstration projects funded through these grants will strengthen our innovation economy and provide the Commonwealth with a roadmap for reducing our most expensive energy loads and securing our energy future.”

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Here’s a fun fact about Russia: it gets a fifth of its energy from hydropower. This might sound shocking for a country whose image is so tightly linked to oil and gas, but Russia has a lot of big rivers and it’s putting them to good use. Now, Moscow is moving into other renewables and, more interestingly, energy storage as well.

Energy Minister Alexander Novak said earlier this week that Russia could find a place among the world’s leaders in solar power generation and energy storage. Russian solar panel makers, the minister added, can already produce an efficiency factor per panel on par with global leaders, at around 20 percent, although some of the world’s leading producers have already exceeded that figure.

Renewables news stories from Russia are not a frequent occurrence, and that’s understandable: there are too many oil headlines and there have not been indications from Moscow that clean energy is a priority. Yet it might well become a priority in the future, as part of the diversification drive among oil-dependent economies.

Earlier this year, Russia launched its biggest renewable power auction to date, seeking bids for 1.9 GW in wind power generation capacity. Bids received topped 2.3 GW, despite unattractive local content requirements.

These envisage a certain percentage of the equipment that will be used in the new installations to be made locally, and this percentage is rising as a way of stimulating job creation. For 2017, it was 40 percent. This did not deter bidders, though. In fact, the world’s top wind turbine producer, Vestas, is opening a factory for turbine blades in Russia to comply with the local content requirements.

Another recent announcement concerns solar power. Despite EU sanctions against Russia, joint research on various initiatives is proceeding as usual: Russia’s state nuclear major Rosatom has partnered with the French Alternative Energies and Atomic Energy Commission on joint research into alternative energy sources and energy storage.

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Energy storage is a good option for frequency response, a storage trade group will tell the Federal Energy Regulatory Commission this month.

Markets would be less efficient and “system costs greater than necessary if resource owners are mandated to provide frequency response service from generators more suited to provide energy and capacity,” the Energy Storage Association wrote in previously filed comments. 

The group is responding to FERC’s request for supplemental comment on its November 2016 notice of proposed rulemaking (NOPR) to begin the process of revising its interconnection rules for both large and small generators. FERC’s concern was that fewer generators were providing primary frequency response.

According to ESA, requiring generators to provide frequency response could produce an oversupply of frequency response headroom, imposing additional system costs. The group noted that many generators are not well suited to provide frequency response because doing so can lower operational efficiency, which will eventually result in higher system costs. Additionally, requiring all generators to provide frequency response would fail to create a market signal.

On the other hand, energy storage, particularly batteries, are well suited to provide frequency response, ESA said. They are fast responding and do not lose efficiency by needing to reserve headroom. In its comments, ESA cited studies by the Electric Reliability Council of Texas that found 1 MW of fast responding resources could be substituted for 2 MW of primary frequency response resources during some system conditions.

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