The stationary energy storage market needs lower battery costs to truly enable market traction in applications like solar shifting. Developers have been pursuing flow batteries as one possible way to lower these costs: This type of battery pumps two liquid electrolytes of different oxidation states across the sides of a proton exchange membrane, and chemistries vary – they include vanadium-redox flow batteries, zinc-bromine, iron-chromium, and zinc-chloride. Harvard University researchers are now pursuing a metal-free flow battery chemistry, based on small organic molecules called quinones. The team claims the quinones are abundant and safer, because they are dispersed in a water solvent, and have tested the battery to about 100 cycles.
The quinone-battery design has some fundamental limitations to overcome: Its large molecules and low voltages may lead to low energy density and low power density. While in theory that may not be a limitation since the developer can build bigger tanks of flow material to increase energy, and use larger-area membranes to increase power, there will be practical constraints. In any instance where the battery is sited on a customer's property or in a suburban distribution substation, there will be a real cost attached to the footprint. This increased land cost will certainly eat into - and maybe even erase - whatever cost advantage the cheaper quinone active material might have.
Moreover, none of these low-cost component options have made an impact on the final project cost for a flow battery system. One key example is EnerVault, which sold a "low-cost" iron chromium flow battery for a final price tag of nearly $10,000/kWh – an order of magnitude higher price than the average lithium-ion system. Naturally, these prices will fall over time as the developers bring down design and engineering costs, but there is still about a 100% difference between flow battery cell costs and flow battery project price, even for big players like Prudent Energy. Much of this inflation is due to the difficulty of commissioning the battery and higher-than-advertised maintenance costs.
The Harvard quinone work remains early stage – their preliminary results are based on very small cells using areas that are only a few centimeters squared. Along the way, there may be opportunity to derivatise their large molecules further to increase cell voltage, which may enhance their low-cost argument further, but more importantly any path forward will require strong partners with energy storage project deployment and management expertise. Those interested should track whether the researchers succeed in developing a full-sized battery prototype with their partner Sustainable Innovations; moreover, those developers that can bring some system-level expertise should engage in exchange for an early and advantageous hedge in this new technology.
In the broader context, others in the flow battery space are also mixing up their approach to their technology and the overall challenge of lowering costs while keeping the technology effective and safe. UK firm RedT, for example, is developing a vanadium redox flow battery, and offers several system sizes ranging from 5 kW to 105 kW. Previously, the company said it was planning on bringing the electrolyte concentration from 1.6 M to 2.5 M up to as high as 4.0 M. However, there are issues in getting to this high a concentration: The toxicity of additives including fluorine and bromine are too high for greater concentrations and there is an increased fire risk for higher molarity vanadium concentrations. Therefore the company is currently offering electrolytes with 2.0 M concentration to balance that risk.
Land costs are often ignored by flow battery developers, but any project integrator or system developer has a very real cost of land associated with a project's footprint. In a recent analysis, we investigated the various cost contributions to stationary energy storage projects, and found that land could be as high as 30% of total system cost, which is only exacerbated as other component flow battery costs are reduced over time. By increasing the electrolyte concentration, and in turn, the energy density of a system you can reduce project costs by significantly decreasing the footprint of the energy storage system.
However, doing so at an increased fire risk may not be worth the potential public relations cost. NGK Insulators suffered from a series of fires with its molten-salt batteries in 2011 and 2012, and has yet to truly recover its sales pipeline and broader momentum that the company was on the cusp of years ago. Despite the increased cost of the electrolyte, increasing energy density remains a very attractive development opportunity on paper, but players like RedT run the risk of being undifferentiated amongst its competitors by reducing molarity. The pursuit of lower overall costs in the flow battery space remains in full swing, and whether it is in incumbent systems like vanadium redox flow batteries or in new formulations like quinone-based flow batteries, significant amounts of research and development remain necessary.
This article was written collaboratively by Cosmin Laslau, Steve Minnihan and Dean Frankel of Lux Research's energy storage team, with Cosmin Laslau as lead author. Based in Boston, Lux Research provides strategic advice and ongoing intelligence for emerging technologies.
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