Earlier this year, the California Energy Commission (CEC) published a $20 million solicitation to fund research projects for the deployment of long-duration energy storage. The objective was to develop a clear understanding of the role that long-duration energy storage (10 hours or greater) can play in helping to meet the state’s mandates to decarbonize the electricity sector by 2045. Lithium-ion batteries were excluded from the solicitation.

The CEC selected four energy storage projects incorporating vanadium flow batteries (“VFBs”) from North America and UK-based Invinity Energy Systems plc. The four sites are all commercial or industrial facilities that want to self-generate power (like solar) and in some cases have the ability to operate off-grid. Invinity’s total scope is 7.8 megawatt-hours (MWh) of batteries across the four projects. Part of the objective is to be able to take those facilities off-grid for an extended period of time, to avoid interruptions to their power supply during grid outages.

What is a VFB, and how does it differ from the more ubiquitous lithium-ion battery? To answer these questions and learn more about Invinity Energy Systems, this week I spoke with Invinity’s Chief Commercial Officer and co-founder, Matt Harper and Joe Worthington, the company’s Communications Director.

Matt is a mechanical engineer by training, and he explained that he has been building clean energy technology for 25 years. For the past 15 years, he has been developing flow batteries.

Vanadium is an element that can commonly exist in four different oxidation states. That just means that it can exist as an ion with different charges. For example, a vanadium ion that is missing three electrons would have a charge of V3+. If you add an electron to it, it converts to a V2+ ion. This transfer of electrons back and forth is what makes VFBs charge and discharge, as the vanadium ions in the battery swing from V2+ to V5+.

Recent years have seen energy storage installations dominated by lithium-ion battery technology around the world. But pumped hydro, for decades the only utility-scale storage asset available, and still the leader with 95 percent of storage’s global capacity, isn’t giving up just yet.

This week, the International Hydropower Association and the U.S. Department of Energy announced an alliance of 11 national governments and more than 60 organizations to speed up the development and deployment of pumped hydro projects around the world.

Such projects typically involve multimillion-dollar budgets and years of work, and in many markets permitting is getting harder because of a lack of suitable locations.

Because of this, “It isn’t easy to build new projects,” said Alejandro Moreno, director of hydropower and marine energy at U.S. Department of Energy, at a Tuesday event launching the alliance.

Another reason why pumped storage installations have stalled is that the business model that has sustained projects until now is being weakened by changing market dynamics.

In Switzerland, for example, pumped hydro plants used to make money by storing cheap nighttime electricity inflows from French nuclear power plants that could then be sold to other neighboring countries, such as Germany, to meet daytime peaks.

Nowadays, though, Germany’s grid is often flooded with wind or solar energy, wiping out demand for Swiss pumped hydro capacity.

As a result, “New pumped storage is not a commercial proposition today,” said Benoit Revaz, state secretary and director of the Swiss Federal Office of Energy.

sonnen, a manufacturer of smart energy storage systems, says it has entered a research collaboration with Stanford University’s Sustainable Systems Lab (S3L) to deploy its intelligent energy storage hardware and load management software in 15 Fremont-area solar-powered homes and in a commercial agricultural facility in El Nido, Calif.

The deployment and continued operation of these projects using the sonnen batteries is funded by the U.S. Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) Network Optimized Distributed Energy Systems (NODES) program.

sonnen support of the research collaboration includes extensive installation and engineering assistance to properly integrate their high-performance battery solutions with the intelligent load controllers and power management algorithms developed in the Powernet Project. The goals of the research collaboration are to provide real-world data, field experiments and analysis to inform the future development of the Powernet Technology platform and the compatible standardization parameters needed to support the increasing adoption of clean energy technology.

“We’re proud to work on this research collaboration with Stanford University’s Sustainable Systems Lab on solar+storage applications in the Northern California area, especially as residents and businesses power through another wildfire season and the uncertainty of 2020,” says Blake Richetta, chairman and CEO of sonnen. “Every project for sonnen is focused on advancing our mission to build a clean, reliable, scalable and affordable energy future for all.”

ARPA-E estimates that using the NODES approach to integrate flexible loads and DERs into the grid in the U.S. could replace 4.5 GW of spinning reserves, representing generation capacity on stand-by in case of outages and unforeseen intermittency and a value of $3.3 billion per year to local utilities in the U.S.

It would be “feasible and cost-effective” to retire more than a gigawatt (GW) of gas and fuel oil peaker plant capacity on New York’s densely populated Long Island within three years, according to a new study.

Long Island is home to 4,357MW of peaker plants, which operate at an annual capacity of just 15% or less, but cost the customers of Long Island Power Authority (LIPA) nearly half a billion dollars a year in maintenance costs.

The new study by Strategen Consulting finds that over a quarter of that capacity, 1,116MW, could be replaced by 2023 using energy storage and a further 1,209MW by 2030, as New York scales up its deployments of solar, offshore wind and energy efficiency measures to meet the state’s target of carbon-free energy by 2040.

Not only is that a feasible aim, Strategen said, but the deployment of energy storage as peaker replacement could save LIPA customers nearly US$400 million, while helping put the island on track to meet those state-wide goals, which are part of New York’s Climate Leadership and Community Protection Act (CLCPA).

The New York Battery and Energy Storage Technology Consortium (NY-BEST), a coalition pitched somewhere between a trade association and a technology acceleration support agency, commissioned Strategen Consulting to figure out a plan through which expensive and polluting peaking capacity in Long Island could be retired and replaced with low carbon technologies.

The amount currently paid in maintenance costs equates to nearly three times the rate for peaking capacity in New York’s Independent System Operator (NYISO)-run markets, while Long Island is already one of the areas of the US subjected to extreme weather events including hurricanes known to be exacerbated in intensity and frequency by climate change.

This is one of four blogs in a series examining current challenges and opportunities for recycling of clean energy technologies. Please see the introductory post, as well as other entries on solar panels and wind turbines. Special thanks to Jessica Garcia, UCS’s Summer 2020 Midwest Clean Energy Policy Fellow, for research support and co-authoring these posts.

Lithium-ion batteries dominate the energy storage scene

Lithium-ion (Li-ion) batteries might be known to everyday consumers as the rechargeable batteries which power our cellphones, cameras, and even toothbrushes. Apart from storing energy for small devices, Li-ion batteries are now being used at a much larger scale to store energy for electric vehicles (EVs) and as storage for renewable energy systems like wind and especially solar.

Bloomberg New Energy Finance reports that prices for battery packs used in electric vehicles and energy storage systems have fallen 87% from 2010–2019, much faster than expected. As the prices have fallen, battery usage has risen.

So have the conversations on what can and should be done with Li-ion batteries when they reach the end-of-use stage. Here we will focus on recycling of lithium-ion batteries from energy storage systems, but for more information on increasing possibilities for second-life uses of EV batteries, see our former colleague Hanjiro Ambrose’s blog and podcast episode.

As a key energy storage technology, batteries are important for incorporating higher amounts of wind and solar power on the grid.

Lithium-ion batteries aren’t the only kind of grid-scale batteries (others include redox flow and newer zinc-hybrid batteries), but they account for the majority. The reason for Li-ion battery storage dominance is that they are lightweight and have high energy density (energy stored per unit of volume or mass).

Solar and wind power project developers are recognizing the financial benefits that incorporating energy storage into their projects provides. Storage has become a major part of microgrid configurations, and commercial and industrial (C&I) enterprises are discovering it can improve the cost-effectiveness of their own installations. Continuing technology advancements bode well for growth in the sector as investments in storage become more attractive.

Analysts have said that global outlays of $374 billion a year will be needed to upgrade the power grid with enough flexibility to account for the intermittent power generation profiles of renewables such as solar and wind. The Rocky Mountain Institute in a recent report detailed the multibillion-dollar potential of energy storage as part of those investments. The group said, “Total manufacturing investment, both previous and planned until 2023, represents around $150 billion, and analysts expect the capital cost for new planned battery manufacturing capacity to drop by more than half from 2018 to 2023.”

Though pumped-storage technology has been around for years, other storage technologies are newer, with the power generation industry still learning about the benefits—and challenges—that storage brings. Financial institutions and other potential investors in the space are working to become familiar with what storage means to the electricity sector, particularly because projects have unique characteristics based on generation sources, location, and their regional market.

“Energy storage is a unique power asset in that it can both discharge and absorb energy, acting as a generation or storage asset as needed [Figure 1],” Ray Hohenstein, market applications director for Fluence, told POWER. “This flexibility allows it to play multiple roles on the electric grid, including regulating power flows, providing critical peak power and ultra-fast black start capabilities, and helping other assets [both generation, and transmission and distribution (T&D)] operate more efficiently—all of which reduces costs as well as emissions.”

“I would say historically, energy storage is still quite new,” said Jacqueline DeRosa, vice president of battery energy storage at Ameresco, in an interview with POWER. “Energy storage hasn’t really been able to be monetized.”

Switzerland’s largest battery storage system has gone into action stabilising the electricity network for transmission grid operator Swissgrid, asset operator Alpiq has said.

Switzerland-headquartered developer MW Storage contracted Alpiq to manage and operate the 20MW / 18MWh containerised battery energy storage solution in the resort town of Brunnen, in the Swiss municipality of Ingenbohl.

According to MW Storage, the project is a “purely privately financed initiative,” and has been “implemented without public assistance and free of subsidies”. A Swiss investment foundation and two local banks financed the project, which is MW Storage’s first “megabattery”.

The containerised lithium-ion battery storage was supplied by MW Storage’s technology partner, Fluence. The system has already pre-qualified in late September to provide secondary control frequency reserve services to Swissgrid and as it also sits in Alpiq’s wider portfolio alongside the company’s hydropower systems, can provide primary control services too, which Alpiq is applying for.

According to Swissgrid guidelines, secondary control power helps maintain supply and demand of energy within a control area to keep the grid operating at its required frequency of 50Hz. Power stations providing this service must be ready to be called upon by the central grid controller, in this case Swissgrid.

Secondary control is activated within a “few seconds” of receiving a signal from the grid and is “typically completed after 15 minutes,” requiring fairly short durations of energy storage when provided by batteries and the Swiss market for this is limited to within the borders of Switzerland. Primary control meanwhile is called upon to balance frequency within half a minute of a signal, and Switzerland is part of the shared European market for frequency containment reserves (FCR) which includes this service along with grid operators in six other countries.