ese batteries, including Invinity Energy Systems, created in 2020 through the merger of flow battery companies based in the UK and US. In this aqueous system the positive half-cell electrolyte contains VO2+ and VO2+ ions, switching from vanadium v and iv oxidation states, while the electrolyte in the negative half-cells contains V3+ and V2+ ions, cycling between vanadium ii and iii oxidation states. Having vanadium species in both half cells has the added benefit of limiting the impact of ‘crossover’ – when ions diffuse across the membrane. In some systems this can lead to electrolyte poisoning and battery discharge.
Invinity say their battery can provide up to 40MWh of storage, run from 2–12 hours and deliver 3.8 times the lifetime energy throughput of a lithium-ion battery. To date they have supplied units to over 70 sites across 15 countries, including a 5MWh battery for an energy superhub in Oxford, which is expected to cut 25,000 tonnes of CO2 emissions in the city per year by 2032. For grid applications, the largest vanadium flow battery facility is in Dalian in northeast China which has been in operation since 2022. Costing $266m, it has a capacity of 400MWh, with a second phase to double that capacity in the works.
Cost is still the major issues that may limit how extensively flow batteries are used for grid storage. ‘With flow batteries, I can just put a massive tank and then it was discharged for 100 hours, but I also have to pay for the material ,’ says Schmidt. Although more abundant than lithium, vanadium is still expensive and on the EU’s list of critical raw materials, which are of economic importance but have high supply risk.
But there is more vanadium in the earth’s crust than copper, according to Adam Tuck, Invinity’s director of technology, and an increased demand will lead to increased production, as well as recycling of the batteries themselves. ‘The electrolyte doesn’t degrade, so even after the end of the 25 year life of the battery itself, we can just take that and put it right back into a new battery,’ he says.
In spite of this, ‘there’s a big push to try and find alternatives to the vanadium’, says Toghill. Imperial College spin-out RFC Power is using a manganese electrolyte in a hybrid redox flow system that combines a Mn 2+/3+ redox half-cell in an acidic electrolyte, with hydrogen gas. During charging and discharging the hydrogen gas is reduced and oxidised, with protons moving across the membrane.
Using manganese – already commonly found in disposable alkaline batteries – instead of vanadium makes a kilowatt hour of storage at least 10 times cheaper, according to Mezzavilla. When charging the manganese is oxidised and hydrogen gas is produced at the negative electrode, with the reverse reaction occurring on discharge. Using a gas rather than a second liquid electrolyte also eliminates the risk of crossover as the reactants are in two different phases.
The technology could also be future-proofed if a hydrogen economy were to become a reality, with hydrogen widely used as a fuel. ‘It could be very interesting to couple the hydrogen that we are using to the hydrogen infrastructure that could be in place,’ says Mezzavilla. He can see a future scenario where chemical plants could use such batteries to store both energy and hydrogen as a chemical feedstock: ‘using hydrogen opens up a lot of opportunities’.
RFC Power is now moving towards commercialisation. They have been working with Shell to improve their battery performance, and with investment from Imperial fuel-cell spin-out CERES Power are developing a kilowatt-level demonstrator which they expect to be operational by 2024.
Still in the realms of basic research, transition metal oxide cluster complexes are also electrolyte candidates, with high stabilities, solubilities and redox chemistries. Toghill says she favours all-iron batteries because ‘[iron] shifts its redox potential considerably depending on the ligand it’s paired with.’ Her group are researching systems pairing a commonly used non-toxic ferro–ferricyanide electrolyte with iron t