Eos Energy Storage, the leading manufacturer of safe, low-cost and long-duration zinc battery storage systems, today announced that it has partnered with EPC firm Nayo Tropical Technology Ltd to deploy the company’s Aurora EnergyBlock™ battery energy storage system (BESS). Eos’ EnergyBlock is part of a project to bring power to underserved areas and will integrate into rural microgrid developments beginning in the African country of Nigeria. Results from the deployment of this microgrid BESS solution will give utilities and energy providers options for the best storage technologies for rural locations and environments.

“Eos’ energy storage solutions are unique as they do not require HVAC or any expensive thermal management systems to cool the storage system,” commented Balki G. Iyer, Chief Commercial Officer of Eos. “The solution is a perfect fit for harsh environments and rural developments like the Nigerian microgrids as it features simple-to-deploy technology and components, delivering an affordable solution that only needs minimal operation and maintenance. This can be a big game-changer for many parts of the world with similar needs and we are quite excited about solving the larger energy problems for many rural communities.”

“We are proud to be leading the way in deploying one of the most advanced energy storage technologies in the world,” said Okenwa Anayo Nas, CEO of Nayo Tropical Technology Ltd. “Our projects will provide lighting to homes and better the livelihoods of the people in remote villages across Africa, beginning with our first of many projects together in Nigeria. From a mini-grid developer’s perspective, Eos offers the most reliable solution with high round-trip efficiency at the lowest cost per kilowatt hour.”

Eos’ clients, including utilities, EPC companies, and storage integrators, benefit from features including:

Battery system integrators must navigate a broad array of technologies and varying market drivers when putting systems together. Andy Colthorpe speaks to Powin Energy and Sungrow about the engineering challenges involved in building lithium-ion battery storage.

This article first appeared in Volume 23 of Solar Media’s quarterly journal, PV Tech Power, in ‘Storage & Smart Power’, the section of the journal contributed by Energy-Storage.news.

In the previous edition of PV Tech Power, we spoke to four leading developers of solar-plus-storage and standalone energy storage projects based in North America about what it takes to get projects over the line, their experiences in the field – and what sort of technologies are making their efforts possible.

This time around, we’ve spoken in depth with two of the system integrator/ manufacturers that supply that segment of the energy storage market as well as projects in other key markets including the UK, mainland Europe and Australia.

Danny Lu, vice president at Oregon, USA-headquartered Powin Energy and Dr Zhuang Cai, R&D director at Hefei, China-headquartered Sungrow, share their insights on what it means to build lithium-ion battery storage systems at scale.

A 21st Century industry
Powin Energy is a pure-play battery energy storage system (BESS) manufacturer and system integrator, having pivoted away from its role as a developer in 2017, while Sungrow will be better known to readers as one of the world’s biggest solar inverter makers.

“Sungrow has focused on power electronics for more than 20 years. Our president (Can Renxian) was a university professor and saw a large potential for renewable energy,” Cai says.

Sungrow has to date supplied more than 100GW of PV inverters. Since first announcing a joint venture (JV) with South Korean battery maker Samsung SDI to create and supply energy storage systems in China with an investment of around US$20 million, the storage JV has accelerated its activities rapidly. By 2016, when it went global, investment in the JV stood at a reported US$170 million. According to Sungrow the JV has already installed more than 900 battery systems, at various scales and for varying applications. The company’s background in solar was instrumental in allowing for the move into energy storage, Cai says.

The Australian energy industry has gathered online for the Energy storage: leading the transition virtual conference, which was held on Thursday 2 July.

More than 700 delegates registered to attend the virtual conference, which was hosted by Energy Editor Laura Harvey. During the three-hour conference, speakers explored the transitioning energy market in Australia and the role that energy storage will need to play as we strive to increase the level of renewable energy in our national grid.

The conference commenced with a presentation from Hydro Tasmania’s Battery of the Nation (BotN) Project Director, Christopher Gwynne, who provided a very well received update on the BotN project.

Delegates were particularly interested in the concept of deep storage which Mr Gwynne introduced – storage with the ability to operate over many hours as an optimal, least-cost choice, a category which BotN falls into.

“Up until recently storage was just storage, but recently we’ve started to point to big differences between what you might call shallow and deep storage,” Mr Gwynne said.

Shallow storage essentially is storage that is four to six hours worth of storage in terms of its duration. Deep storage has a longer duration, in the range of ten to twelve hours.

As the market transitions to having more input from renewable sources, forms of short, or shallow storage, are the ones we need in place first. But according to Mr Gwynne, most of the analysis that’s going on around the world is showing that as markets move further into their transformations, longer, deeper storage options will be required in order to maintain a stable and reliable power system.

“What this means is that by the mid to late ‘20s, we’re going to need some of these longer duration, deep storage assets to start to come into the market,” Mr Gwynne said.

“The value of this type of storage is in the fact that it’s better placed to manage longer term variations in supply, like what we might see during a wind drought, or a successive number of days of low solar output in the system.

“When dealing with these conditions, you’re going to need deep storage to help manage the reliability of the system.”

Next up, Matt Rennie, Energy Transition Lead Partner at EY, discussed storage opportunities in the evolving energy market.

The need for inexpensive, fast, reliable chemistries and technologies for storing renewable energy is breaking the lithium-ion mould. Get used to the terms “beyond-LIBs”, “strain engineering” and “hydrogen-bonding metal hydrides”, and enter the labs of Professor Guoxiu Wang at the University of Technology Sydney and Professor Kondo-Francois Aguey-Zinsou at the University of New South Wales.

Professor Aguey-Zinsou’s new technology could provide energy at 2 cents per kilowatt hour and is expected to be patented within weeks.

At UNSW’s Materials Energy Research Laboratory in nanoscale (MERlin), Aguey-Zinsou has been working on storing hydrogen by bonding it with solid materials, such as magnesium nanoparticles.

It’s a safer approach than storing hydrogen in gas or liquid form; and many hydrides act like a sponge for hydrogen, absorbing it to the high volumetric capacity required for efficient storage of energy.

Aguey-Zinsou, who has spent 20 years investigating hydrogen-bonding metal hydrides, has applied his breakthrough technology — a hydrogen-absorbing metal alloy that includes titanium — to an energy-storage system designed for residential and commercial use, which could be commercialised in early 2021.

“It’s a game changer in how we use electricity,” the Professor told the Sydney Morning Herald, likening the development to “the internet revolution”, and emphasising the safety of the chemistry involved — “It’s not flammable,” he said.

The resulting residential battery system, engineered at UNSW’s Hydrogen Energy Research Centre, which has received $10 million in funding from Providence Asset Group, is expected to have a 60 kWh capacity and occupy the space of a mini-fridge with a height of about 130 cm.

A co-founder of Providence, Alan Yu, has said the batteries will be manufactured in Australia and will be branded LAVO.

He also hopes to scale the system by containerising numerous battery units to be used at scale on projects such as the community 4.5 MW Manilla Solar Farm near Tamworth, developed by Providence Asset Group with the help of $3.5 million in funding from the NSW Government Regional Community Energy Fund.

A National Renewable Energy Laboratory (NREL) study concludes that by 2050, hydrogen storage lasting for two weeks “is expected to be cost-effective.”

The global consulting firm DNV GL reached a similar conclusion in April, saying that hydrogen is the “first viable option” for seasonal storage, to help balance renewable generation.

Hydrogen storage with just one week’s duration could become cost-effective by achieving capital costs for the power equipment below $1,507 per kW, and capital costs for underground hydrogen storage below $1.80 per kWh, said the study’s lead author Omar Guerra, an NREL research engineer.

The power equipment begins with an electrolyzer to produce hydrogen from water—a process that can be powered with solar or wind power. Later, to convert the hydrogen to electricity, the power equipment would be either a fuel cell or a gas turbine. Researchers are also developing a reversible fuel cell that also operates as an electrolyzer.

NREL’s study also found that pumped hydro and compressed air energy storage with one day of discharge duration would be cost-competitive in the near future.

Here are the study’s cost estimates, provided by NREL—with the cost for storing the hydrogen, compressed air, or pumped water shown as the energy capacity cost (in $/kWh capacity, not $/kWh generated):

Siemens Energy and EnergyNest have entered into a long-term partnership to develop thermal energy storage solutions for industrial customers. The two companies are exploring the use of excess renewable electricity to charge a thermal battery, which would in turn release steam when needed to provide power — lowering the plant’s natural gas demand, while increasing flexibility.

Niche tech

Thermal storage has long been considered vital to decarbonization, yet the market for the technology has remained niche and expensive. This is a reality recognized by Siemens and EnergyNest, with the two companies laying out their intent to create modularized and standardized thermal storage systems – improving both the efficiency and economics of the technology into a scalable model.

Thermal storage is currently a $4.35 billion market, small potatoes in the energy world. And while the technology is currently held back by limited efficiency and even more limited project economics, proponents of the technology hold to the idea that thermal storage can offer higher power capacity, improved cycle life and better overall system reliability, in comparison to lithium-ion batteries.

Siemens and EnergyNest aren’t the only companies operating in the thermal storage sector, so what other innovations are being made to guide this niche technology into the mainstream?

Development stage

It’s not just private companies looking to expand the scope of thermal storage. The National Renewable Energy Laboratory (NREL) has launched a project aimed at increasing the efficiency of thermal storage to then use the energy to drive a turbine-generator set. Specifically, NREL is looking to develop a system that uses electricity to power a high-performance heat exchanger, which will heat inexpensive solid particles to over 1,100 C. The particles will be stored in insulated silos for up to several days. When electricity is desired, the hot particles will be fed through a fluidized bed heat exchanger, heating a working fluid to drive a Brayton combined-cycle turbine attached to a generator.

Speaking of Brayton Energy, the company is currently developing what it calls a “key component” to integrate turbomachinery into a cost-competitive thermal energy storage system. In English, that means that Brayton is looking to create a system in which each turbo-machinery stage is designed to act as both a compressor and turbine, alternating between charging and discharging cycles. This system simplification and consolidation of parts is expected to increase efficiency and reduce capital costs.

When asked how to best plan for battery storage in a future power mix, utilities, resource planning consultants, and researchers had the same answer: It depends.

The key variables are the system’s current and projected renewables and storage penetrations. But drilling into the complexities of planning for the right amount of battery storage in a least-cost future resource mix dominated by renewables revealed critical insights about how to properly value storage for the reliability it provides.

Planners have made “substantial progress” in “capturing the complex value of battery storage for reliability,” National Renewable Energy Laboratory (NREL) Senior Researcher and Group Manager Daniel Steinberg said during a California Energy Storage Association (CESA) May 22 webinar. Ways to value shorter duration storage in planning are “actively being improved,” but long-duration storage methods are only “developing.”

Arizona Public Service (APS), the first investor-owned utility to choose solar-plus-storage over a natural gas peaker unit, uses “multiple future scenarios” to plan for its storage needs, APS VP for Resource Management Brad Albert told Utility Dive. “There is no perfect scenario. We could not have predicted a pandemic in 2020. Strategic planning requires judgments.”

There are conditions in which overbuilding renewables is more cost-effective than deploying storage. And the value of battery storage for reliability changes significantly as costs fall and penetrations of variable renewables and storage rise on the system. Precise analytics, like the Effective Load Carrying Capability (ELCC) calculation, could simplify planning decisions, some stakeholders said. But others said no calculation substitutes for judgment.

From bidding to planning

Though utilities have long recognized the value of pumped hydro, compressed air, and concentrating solar’s thermal storage, those technologies have not proved cost-effective and scalable for storing energy. Two recent solicitations turned planners’ attention to batteries.

FlexGen, an energy storage system integrator that counts GE and Caterpillar among its backers, said this week that a lithium-ion battery storage system it was supplied was used by an Indiana utility to black start a 77MW natural gas plant.

Thermal power plants that go offline require black starting and the application is considered an essential service for the grid. While the theory of using batteries to perform this application, akin to “jump starting” a vehicle, was sound, grid-scale battery energy storage systems did not start actively doing so until around 2016, when Energy-Storage.news reported on projects in Germany and later in California that successfully proved the case in real-world settings.

Black start is still done using diesel generators in many places, including at FlexGen’s unnamed “leading Indiana utility” customer. FlexGen deployed a 12MW / 5.4MWh short duration lithium-ion battery storage system which has successfully black started one of two 77MW gas turbines.

As well as being zero emissions resources, FlexGen claims that batteries can perform the application at half the cost of diesel generators, coming online when there is a blackout to repower turbines. FlexGen said its proprietary software, called HybridOS can enable the functionality at any commercially available turbine. While energy storage systems have been used to black start power plants already, FlexGen claims its Indiana system black started a 112MVA generation set-up transformer (GSU), making it the largest black start of its kind of a transformer in the US to date.

“FlexGen provides integral capabilities like black start for utility clients’ existing power plant sites through cost-competitive battery storage assets. We look forward to helping Indiana further integrate carbon-free technologies that increase the reliability of the electric system,” FlexGen chief operating officer Alan Grosse said.