In renewables storage, an old technology finds a new home

Since the spring of 2023, more than 7,000 Albertans have gotten their power from a shed north of Medicine Hat.

Inside the grey, steel building are 38 shipping containers stacked on a dirt floor. They hold polyethylene tanks of electrolyte — mostly water — that stores excess power from a nearby 14-megawatt solar farm before feeding it onto the grid.

While lithium-ion dominates the battery market today, the rows of redox flow batteries inside the shed could be part of a storage solution as Canada adds more solar, wind and other renewable energy to electricity grids.

“If you’re looking for a battery that’s going to provide real-time regulation of the grid, 24 hours a day, then ours comes with huge advantages,” said Matt Harper, President of Invinity Energy Systems, the Vancouver-based company that manufactured the flow batteries that form part of the Chappice Lake Solar+Storage Project. 

Redox flow batteries are not new. They appeared in scientific journals in the early 1950s and the US space agency NASA built prototypes in the 1970s. But the technology struggled to gain commercial traction.

Decades on, they are getting a second look, as Canada adopts more renewable energy to meet net-zero emissions targets by 2050, and needs to store electricity from intermittent sources such as wind and solar.

Big lithium-ion battery plants — such as Ontario’s Oneida project that went online this summer — get the most attention and investment. But flow advocates argue their technology needs a fraction of the rare earth metals used in lithium batteries, have significantly longer lifespans, and come without the risk of fire that has set back lithium storage projects in the US.

As Prime Minister Mark Carney compiles a list of nation-building projects in response to US tariff and sovereignty threats, advocates say flow batteries can provide bulk, grid-scale energy storage for a national electricity grid to drive clean economic growth.

Big and heavy

To be sure, redox flow batteries have very low energy density, storing about one tenth as much power per unit volume as lithium-ion. They need to be big and heavy to be useful for long duration energy storage (LDES) projects.

Rather than store electricity in solid electrodes — such as lithium-ion batteries that power everything from EVs to laptops — flow batteries use positively and negatively charged liquid electrolytes.

These are pumped from separate tanks through “cell stacks”, which look similar to fuel cells, where they exchange ions through a membrane and electrons through copper wire. 

In chemical terms, one electrolyte reduces while the other oxidizes, hence the name “redox.”

There are as many flow batteries as there are electrolytes, provided the pair being used have enough reactivity and voltage between them. 

While these batteries will never run a cell phone or an electric car, they can, and have, worked as bigger storage units.

“There are pros and cons to every chemistry,” said Marc-Antoni Goulet, assistant professor of chemical and materials engineering at Concordia University in Montreal.

“I think there’s room for improvement by maybe a factor or two or three, but is it ever going to be as energy dense as lithium-ion? I don’t think so,” Goulet said. “It’s very unlikely that something floating around in water will ever have the energy density of a solid electrode.”

The first redox flow battery to reach commercial scale was developed by Australian chemical engineer Maria Skyllas-Kazacos in the early 1980s. She used vanadium — a good conductor — in both positive and negative electrolyte, cycling through four separate oxidation states during charge and discharge, two on either side.

This is the technology behind the all-vanadium redox flow battery at Chappice Lake. It can store 8.4 megawatt hours (MWh) of solar power, and is the only vanadium flow battery deployed at scale in Canada.

‘Fundamentally different’

Harper, an engineer by training, began working with flow batteries in 2005 at VRB Energy, the original licensee of the all-vanadium technology in North America, which was sold to Prudent Energy in 2009. 

Harper started his own firm, Vancouver-based Avalon Battery, in 2013 when “really interesting opportunities” were emerging. 

“Utility scale solar was going through an absolutely transformational shift, and I remember looking at that and thinking our batteries could be a really good fit,” he said.

At the time, he felt vanadium flow batteries were built all wrong for a marriage with solar projects. 

The batteries were designed like small chemical plants, with electrolyte silos and concrete foundations that were slow to erect and hard to expand.

“They took two and a half years to build,” Harper said. “Conversely, solar farms were being rolled out in megawatts per week. We realized that if we were going to have a place to play alongside solar, we were going to have to come up with a fundamentally different architecture for the battery.”

Avalon Battery merged with UK-based redT energy in 2020 to become Invinity Energy Systems. A year later, the combined company deployed the VS3 all-vanadium flow battery, designed with two cell stacks suspended over top electrolyte tanks.

These are typically sold by the shipping container — six individual batteries wrapped in a steel shell 2.5 metres tall and wide, and 6 metres long, each weighing 24,600 kilograms with a total storage capacity of 230 kilowatt hours (KWh). 

They are easily shipped, stored and networked — and can hold power from the first day of operation.

These “six-packs” might have low energy density relative to their size, Harper said. 

But wherever bulk isn’t an issue — such as a solar farm — they can be packed cheek by jowl and stacked several units high, putting every square centimetre of available space to work storing power. 

The same can’t be said for grid-scale lithium-ion projects, where individual batteries must be spaced a certain distance apart to prevent thermal runaway — the uncontrolled, self-sustaining rise in battery temperatures that can lead to fires and explosions.

Flow batteries, by contrast, cannot burn and operate at much cooler temperatures.

“The technology is fundamentally less energy dense than lithium-ion on a watthour per kilogram or watthour per litre basis,”  Harper acknowledged. But per acre — such as on a solar farm — it is equal to, or slightly better, than a lithium-ion system.

Volatile price

The drawback is the volatile price of vanadium. It is the 13^th most common metal in the Earth’s crust — more common than copper or nickel — but rarely occurs in large deposits and very little of it is mined directly. 

Most vanadium is a byproduct of iron ore mined in China, Russia, South Africa and Brazil for use in strengthening steel products.

Prices have been volatile in recent years, but may get more expensive if vanadium plays a bigger role in energy storage.

Vanadium electrolyte accounts for 30-40 per cent of VS3’s product cost, Harper said, making their batteries roughly twice as expensive as lithium-ion, kilowatt for kilowatt.

Despite the relatively high price, Harper said their battery is still cost competitive with lithium-ion because it has a longer lifespan and will not degrade over time.

Vanadium electrolyte is extraordinarily stable and any loss in the VS3’s storage capacity — estimated at less than 0.5 per cent per year — is a consequence of aging hardware, he said.

The VS3 is rated for at least 25 years of continuous operation — the approximate lifespan of most solar and wind farms — and can be fully charged and discharged any number of times without hastening capacity loss.

After 25 years, the battery is 99 per cent recyclable by weight. Its electrolyte, the most expensive single component, is immediately ready for service in a new battery.

Grid-scale lithium-ion, by contrast, is typically rated for no more than 15 years. It loses capacity much faster, is limited in how deeply and how often it can be discharged, and is difficult to recycle. 

These factors bring the VS3’s levelized cost of storage — price per megawatt of delivered electricity over the battery’s lifetime — below that of lithium-ion, Harper said.

Invinity — which has manufacturing facilities in Vancouver, Scotland and China — has about 80 megawatt hours of storage capacity installed globally, with another 100 megawatt hours in the pipeline.

Chappice Lake is Invinity’s only installed capacity in Canada, but Harper expects this to change as more renewables are added to the country’s power mix. 

Invinity has its eye on wind and tidal projects in Nova Scotia, where the province has ambitious plans to expand its fledgling offshore wind energy industry. But in most jurisdictions, the longevity and scalability of the VS3 — or Invinity’s new battery, Endurium — has not yet justified the higher cost.

For his part, Goulet expects flow batteries will make more sense in some provinces than others, if and when the price comes down.

“BC and Quebec don’t need flow batteries all that much, because we have a bunch of hydroelectric power, which already behaves like a battery — cut back the flow of water when you need to store it and let it out when you need to use it,” he said.

“It’s all the other provinces, like the prairies, the maritimes, the territories — anywhere you could install more intermittent renewables — who could benefit from cheap flow battery technology,” he added.

Edward Roberts, professor of electrochemical engineering at the University of Calgary, has been working since the early 1990s to make vanadium flow batteries cheaper, “although I’m not sure how successful we’ve really been.” 

Still, Invinity hopes that economies of scale — and the potential of sourcing vanadium from petrochemical waste — will bring their batteries within 1.2-1.5 times the installed cost of lithium-ion. 

Organic alternative? 

Some flow battery advocates are moving away from vanadium altogether.

Michael Aziz, a professor of materials and energy technologies at Harvard University, pioneered the idea 15 years ago of stocking flow batteries not with vanadium, but with organic molecules.

“I noticed that some groups were successfully using organics in fuel cells, and a flow battery is basically a fuel cell that can run forward and reverse,” Aziz said.

The trick was finding an organic molecule which could tolerate life in a battery without rapidly decomposing, and hold a charge. His search led to quinones, a class of molecules used, among other things, for dying fabric. 

Aziz and his colleagues focused on DCDHAQ, a quinone that can be cheaply sourced from coal tar and organic compounds in crude oil. When dissolved at sufficient concentrations, it produces an electrolyte with energy densities on par with vanadium.

DCDHAQ degrades slowly over time and at a rate unaffected by the number of charge-discharge cycles. A flow battery using this quinone could lose 3-4 per cent of its capacity over 20 years, a loss easily supplemented with new electrolyte.

“We are essentially a drop-in replacement for vanadium,” said Eugene Beh, CEO and co-founder of Quino Energy, a startup using Harvard’s work on DCDHAQ.

Flow batteries made for vanadium electrolyte could run as well — and without any reengineering — on Quino’s organic alternative, which can be produced anywhere there are fossil fuels.

“I’ve been going to these companies and telling them, you don’t need to change all your engineering, or give up all the hard work that’s already gone into your batteries,” Beh said. “I’m just asking you to use a cheaper electrolyte.”

Quino Energy — which makes DCDHAQ electrolyte at a facility in Buffalo, New York — expects to achieve price parity with vanadium electrolyte by the end of 2025, Beh said.

By 2029, once supply chains are firmly established, he plans to be a quarter of the price, making installed flow batteries cost competitive with lithium-ion.

The “organic aqueous redox flow battery” has not yet been demonstrated in systems over 100 KWh, but larger systems just require more cell stacks and more electrolyte tanks. 

“Soon, we think, the default chemistry for flow batteries isn’t going to be vanadium, but our organic electrolyte,” Beh said.