Arlington Energy, a clean energy investment group, has announced plans to build out a 1GW portfolio of energy storage and gas peaker projects across the UK after securing initial funding of £200 million (US$255 million) from an offshore fund of institutional investment.

The sites, ranging from 5-50MW, will be developed over the next three years with the first aiming for completion in July 2019 as part of 250MW slated for completion by October.

Around 40% of the portfolio will be made up of standalone battery storage, with over 100MW anticipated to be in the ground under the first tranche of projects.

While the company has yet to reveal where its projects will be, a 20MW gas site in Chesterfield and a developed 40MW energy storage site in Bedford was recently sold to Arlington Infrastructure, the company set up in May 2018 to build out the portfolio.

Matt Clare, director of Arlington Energy, said: “Securing this level of funding has been a fantastic achievement for us, and for the UK energy sector. We are extremely pleased to be able to deploy so many assets in the UK to support the grid network.”

The company has yet to select its technology partners for the storage projects, and is working with advisory services firm DNV GL to provide technical assistance on procuring and deploying the most suitable assets for the portfolio.

“They will be tendering every top manufacturer and system provider with experience in energy storage globally,” Clare said.

The projects will rely on Capacity Market contracts it hopes in to win in February 2019’s T-4 auction to support a merchant trading strategy in what it sees as a distributed energy market susceptible to system volatility.

This approach was recently called for by a panel of energy storage providers at the UK trade event Solar & Storage Live, which claimed that investors needed to “come to grips” with merchant risk following years of subsidy-backed opportunities.

South Korea’s government is planning for 100MW of battery storage as part of a nearly 3GW hub of solar PV and wind on reclaimed land in Saemangeum, which is an estuarine tidal flat on the coast of the Yellow Sea.

A spokesperson from Saemangeum Development and Investment Agency (SDIA), an agency run under the Ministry of Land, Infrastructure and Transport, told Energy-Storage.News that the agency will oversee 2.6GW of projects. This will include 2.4GW of solar, 100MW of wind and 100MW of battery storage.

Meanwhile, the Ministry of Agriculture, Food and Rural Affairs (MAFRA) will oversee 400MW of solar PV.

The project overview was announced this week, but this vision is very much in the early stages and detailed plans are only likely to be brought out at a later date. The projects would be located on reclaimed land at Saemangeum, which the Korean Government is hoping to turn into a global business hub and free trade hub of Northeast Asia, after a major damming operation known as the Saemangeum Seawall Project, completed in 2010, said to be the largest dyke in the world.

Separately, a release from the Jeonbuk Province government announced plans for up to 1GW of offshore windfarms off the coast of the city of Gunsan, as well as plans to build a port behind the offshore wind farm to attract manufacturing companies.

Back in September SDIA issued a release notifying that it had signed a memorandum of understanding (MoU) with Rena International, a foreign investment company established by Korean company, Geumgang ENG, jointly with China-based PV firm Renesola, for them to invest around KRW55.5 billion (US$49 million) in the Saemangeum Industrial Complex from 2018 to 2020, for assembling PV modules and manufacturing energy storage systems, while creating 120 jobs in the process.

Under another MoU, NemoENG would also invest KRW47.5 billion in Saemangeum Industrial Complex (lot 2) to produce floating and mooring systems for solar PV as well as energy storage devices from 2018 to 2022. South Korean state-utility Korea East-West Power Co. (EWP) recently completed a 3.5MW floating solar project at a coal-fired power plant.

The Federal Energy Regulatory Commission has given every grid operator in the country a December deadline for submitting plans for integrating energy storage into capacity, energy and ancillary services markets.

We’ve been covering some of the details of this momentous grid policy development at GTM Squared, including a deep dive into PJM’s latest straw proposal for meeting this mandate.

At the same time, FERC has also given each independent system operator (ISO) and regional transmission organization (RTO) leeway to meet Order 841’s requirements in ways that build on energy storage integration work already in progress. And in some cases, ISOs and RTOs are making big changes in energy storage-market integration well ahead of Order 841’s schedule.

That description fits the ISO New England’s recently filed proposal for integrating batteries and other fast-acting storage assets into its energy markets. While the “Storage Revisions” plan filed with FERC earlier this month doesn’t take ISO-NE all the way to full Order 841 compliance, it does contemplate important and valuable changes in market rules for batteries and other “continuous storage facilities” coming as early as April 2019, eight months before Order 841’s implementation deadline.

Much of the energy storage industry’s focus has been on mid-Atlantic grid operator PJM, which holds nearly 40 percent of the country’s existing large-scale battery storage power capacity, and has been updating its straw proposal for Order 841 compliance ahead of a December filing deadline.

The $2 million contract is part of the DoE’s FY2018 SETO funding programme and will develop a best-in-class next generation heliostat design, optimised for CSP technology projections of the next decade.

SolarReserve is partnering with South Africa’s Stellenbosch University and New Mexico based Sandia National Laboratories to conduct research and development.

The aim is to be able to use storage to store solar energy to meet peak demand periods, even at night.

Heliostats are the dual-axis solar tracking mirrors that concentrate and focus the sun’s energy onto an energy collection receiver atop a central tower.

Within the receiver, fluid flows through piping that forms external walls; this fluid absorbs the heat from the concentrated sunlight. In SolarReserve’s technology, the fluid utilised is molten salt, which is used both as a heat transfer fluid, as well as a thermal energy storage medium.

Kevin Smith, SolarReserve’s CEO, said: “We are excited to participate in this initiative and aggressively drive innovation that will lower delivered cost of solar electricity that has the added benefit of round-the-clock availability through energy storage.

“Through this award, we can develop breakthrough solutions for cost-effective sustainable energy now and for the generations to come – with the goal of fostering new industries and creating thousands of U.S. jobs.”

The heliostat field can account for up to 50% of a CSP project’s capital cost, hence it is a critical component in any cost reduction initiatives.

‘Europe’s largest’ energy storage pilot project at an industrial site, combining 2MWp of rooftop solar with a total of 4.2MWh of energy storage across a lithium-ion battery system and two flow batteries has been inaugurated in Belgium.

The distributed resources have been integrated into the microgrid ‘MiRIS’ (‘Micro Réseau Intégré Seraing’), a project “demonstrating the advanced integration of intermittent renewable energy resources” with batteries, producing a dispatchable energy resource, at the headquarters of CMI Group, a manufacturer of steam heat recovery systems, boilers and other thermal equipment for industry. CMI claims it is the largest project of its type so far in the continent.

Located in Seraing, Belgium, CMI subsidiary CMI Energy’s president said the project can help “eradicate the major flaw” of renewable energy, namely it’s intermittency of production. When the project was first announced, Jean-Michel Gheeraerdts also acknowledged that energy storage has other benefits that could increase its value even further.

“Energy storage and management can be applied in a number of fields as an alternative to diesel generators for unconnected regions, as a way of deferring investment in parts of the network, as a means of optimising existing photovoltaic or wind systems, and as an enabler of participation in the primary or secondary reserve markets,” Gheeraerdts said.

• BYD has supplied the lithium-ion battery system.
• VIZn Energy supplied one of the two flow battery systems: 400kW / 1200kWh (2.5 hours duration)
• Sumitomo supplied the other flow battery system: 500kW / 1750kWh (3.5 hours duration)

CMI integrated the lithium-ion battery system, while other partners included other CMI subdivisions which worked on power control systems and filling the flow batteries’ electrolyte tanks, PV installer Enersol and power supply specialist JEMA which installed the PCS.

The first element is pumped storage hydropower, a technology that has been steadily refined over the past 100-plus years. It is currently the most reliable, efficient and durable form of electricity storage. Pumped storage hydropower schemes are mainly found in mountainous countries, as they require a difference in elevation between two reservoirs, as well as sufficient amounts of water. When large volumes of power are generated, the excess electricity is used to pump the water from the lower reservoir to the higher one. If electricity demand increases, the water flows back down and drives turbines that in turn generate power. Pikl has implemented this principle completely underground. Subterranean tunnels are used to create the difference in elevation between the two underground reservoirs needed to produce electricity, regardless of the topography. This minimises the area required, and simplifies both the process of finding a location as well as the mandatory approval procedure.

Heat accumulators, where the thermal energy is stored, form the second component of the new storage concept. Thanks to its high specific heat capacity, water serves as an additional thermal energy storage medium for the underground pumped storage power plant. Renewable energy is used to heat the water to up to 90°C. Thermal energy is stored and used by means of heat exchangers installed in the underground reservoirs. When demand for heat is high, it can be supplied directly to consumers via district heating transmission lines.

Franz Georg Pikl also integrated district cooling technology into the concept – this method of cooling buildings is becoming increasingly significant – in the shape of absorption chillers. When required – in other words, on warm days – the hot water drives the chillers, which produce cooling energy that is distributed to customers along district cooling transmission lines. To ensure a constant supply of cooling energy to various temperature zones, this system can be modified by cooling the water of the underground pumped storage hydropower scheme – which could then be labelled a “cold-water pumped storage hydropower plant.”

Europe’s largest industrial energy storage facility has been inaugurated in Belgium.

The facility is a pilot project comprising energy storage and solar PV integrated with a microgrid. It is operated by CMI Energy at the company’s international headquarters in Seraing.

CMI makes industrial boilers, steam generators and HRSGs for concentrated solar power with thermal storage and the MiRIS (Micro Réseau Intégré Seraing) storage facility will help power the company’s headquarters, which currently consumes 1.3 GW a year.

CMI said that the plant is also intended “to demonstrate advanced integration of intermittent renewable energy resources with battery-based energy storage to produce a fully dispatchable renewable energy resource”.

CMI Energy president Jean-Michel Gheeraerdts said: “We now have ways to use green energy sources that eradicate their major flaw: intermittent production. Energy storage and management can be applied in a number of fields as an alternative to diesel generators for unconnected regions, as a way of deferring investment in parts of the network, as a means of optimizing existing photovoltaic or wind systems, and as an enabler of participation in the primary or secondary reserve markets.”

MiRIS consists of a 2 MW photovoltaic system with 6500 rooftop and carport panels, plus 4.2 MW of energy storage comprising a lithium-ion battery system and two different flow battery systems.

The technology showcase interconnects with the building’s electrical network and its DSO 15kV distribution service connection.

Gheeraerdts said that MiRIS “will facilitate investigation of the interoperability of renewables and different energy storage technologies for a variety of user energy profiles, particularly with respect to renewable energy time shifting and energy resale to the grid. MiRIS will also enable evaluation of microgrid ‘islanding’ operation, potential grid ancillary service opportunities, and the influence of user demand response.”

The U.S. residential energy storage market overtook front-of-the-meter installations for the first time in the second quarter of 2018, according to a joint report by Wood Mackenzie Power & Renewable Energy Consulting and the Energy Storage Association.

The incentive program from SRP comes in addition to new tariff structures from other regulated utilities in Arizona, which are expected to encourage more residential storage, Wood Mackenzie Senior Energy Storage Analyst Brett Simon told Utility Dive last month.

The study is “a landmark effort to understand the value” that distributed energy storage will have on customers and utilities, NREL said.

“Phase 1 is already underway,” Adarsh Nagarajan, NREL research engineer, told Utility Dive in an email statement. “The focus is more about collecting diverse data,” he said.

The first phase will manage granular resolution data on battery performance along with advanced battery testing data. Customer battery use and battery system performance data could be used in future stages of the NREL study “to develop modeling and simulation tools to assess the customer benefits and distribution network impacts of” battery systems.

The goal is to collect data from about 450 of the potential 4,500 SRP storage customers, according to Nagarajan. SRP reports that nearly 500 signed up, reserving their incentive. Battery systems charged by on-site renewable resources, like solar panels, are also eligible for the 30% federal tax credit.

Researchers in Akron, Ohio, are filling silos with sand in hopes it might lead to the next breakthrough in energy storage.

Echogen Power Systems, founded 11 years ago on the principle of capturing heat for energy, is among 10 recipients to receive millions of dollars in Department of Energy funding for long-duration energy storage.

In the Midwest, a team from Michigan State University was also selected. A common theme between the Ohio and Michigan projects: heating up cheap materials to reduce storage costs.

“In order to get a large penetration of renewable energy onto the grid, we really need low-cost and robust forms of energy storage,” said James Klausner, chair of Michigan State University’s Mechanical Engineering Department.

By storing thermal energy in relatively cheap materials, the researchers are looking for a low-cost, long-duration technology to support widespread deployment of renewables.

Echogen received $3 million and MSU received $2 million through a DOE Advanced Research Projects Agency-Energy (ARPA-E) program. The DAYS program focuses on storage for roughly 10 to 100 hours, and projects must also demonstrate a path to commercialization.

Echogen’s project turns thermal energy into electricity with sand as the storage medium. The process involves using a carbon dioxide heat pump cycle to convert electricity into thermal energy by heating a reservoir, which is converted back into electricity on demand. The product is geared toward larger-scale projects at 50-100 MW capacities.

“Using these low-cost storage media, we can keep increasing capacity for megawatt hours almost indefinitely,” said Echogen chief technology officer Tim Held, adding that storage durations could exceed 100 hours.