Scientists from the University of Birmingham in the UK and the University of Melbourne have investigated the potential of liquid air energy storage (LAES), which has so far seen development for large-scale energy storage.
LAES has been mostly developed by UK-based specialist Highview Power, which is currently preparing to deploy the technology in a range of locations including a 400MWh system in the United States, a 250MWh project in the United Kingdom, and a 300MWh facility in Spain.
LAES currently has a technology readiness level (TRL) of 8, based on a scale from one to nine, with nine representing mature technologies for full commercial application.
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Liquid air energy storage is described by the research group as a concept where electricity is stored in the form of liquid air or nitrogen at cryogenic temperatures below -150 degrees Celsius. It charges by using excess electricity to power compression and liquefaction of the air which is then stored as a liquid at temperatures approaching -196 degrees Celsius. To discharge, the liquid air warms and becomes a pressurised gas that operates a turbine to generate electricity.
It was conceived for utility-scale applications and an output ranging from 5MW to 100MW.
“Compared to pumped-hydro storage, which is based on the same basic concept, cryogenic energy storage has the advantage that it is a technology that can be produced through an established industry and without any expensive or rare material,” research co-author Adriano Sciacovelli told PV Magazine.
“Furthermore, there are no degradation issues and no need for specific locations or the orographic conditions that are needed for pumped-hydro, or of an underground cavity, as for compressed air storage.”
Compared to these storage technologies, however, liquid air energy storage has the drawback of a lower cycle efficiency, for both charging and discharging, which is close to 60 per cent. Nonetheless, cycle efficiency can be increased through integration and co-location of LAES with nearby processes, for example liquefied natural gas (LNG) terminals.
An LAES system produces hot and cold streams during its operation, both during air compression for charging and evaporation for discharging, and these streams can be utilised to improve the system efficiency, or in several industrial process.
“Currently, all existing projects are being developed for grid support but decarbonisation targets will likely push this technology closer to industrial processes that waste a lot of heat,” Sciacovelli said.
The ideal location of cryogenic storage is at a grid node with a high share of renewables or an industrial park with large waste of heat.
“Cryogenic storage is not directly competing with lithium-ion batteries as it provides storage for a longer duration, from over 10 hours,” Sciacovelli said.
“By contrast, for lithium-ion storage, when it is needed for more than between four and six hours, bankability, currently, remains an issue.”
In terms of costs, the research group estimated that an LAES system can be built at between AU$480-$960 per megawatt-hour.
“Investment return is estimated at approximately 20 years for a standalone system without integration with an industrial facility for use of excess heat,” research co-author Andrea Vecchi said.
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“An ideal location in an industrial park, however, may significantly reduce this time frame.”
All existing projects were defined by the research team as bankable, although they stressed that these positive business cases are favoured by certain conditions, including a determined price structure in the energy market and the presence of a grid unable to support high levels of renewable energy penetration.
“LAES systems are, so far, conceived as strategic assets for the power network,” Vecchi said.
“They can provide not only grid balancing but several grid services.”
