Design, techno-economic analysis, and comparative assessment of high-temperature molten salt electric thermal energy storage systems for industrial heat decarbonization in Alberta, Canada

Alberta’s industrial sector requires substantial high-temperature process heat, yet its extreme ambient temperatures, which can reach −40 ∘C, present challenges for thermal energy storage deployment. This study evaluates the techno-economic feasibility of electric thermal energy storage systems using binary chloride salts (50 wt% NaCl: 50 wt% KCl) contained in engineered concrete for delivering industrial heat at approximately 700 ∘C. A single-tank configuration with an embedded air to salt heat exchanger is operated under different thermal charging configurations, including electric heating powered by solar photovoltaic farms, wind farms, or the grid, and beam-down volumetrically absorbing concentrated solar thermal systems. Nine scenarios were evaluated under four carbon pricing trajectories over a 30-year project lifetime: CP0 (carbon price frozen at $170/tCO2e after 2030), CP15 (continued rise of $15/tCO2e annually), CP30 (accelerated increase of $30/tCO2e annually), and CP45 (high-stringency case with $45/tCO2e annual increases). Key performance indicators include round-trip efficiency, levelized cost of heat, land footprint, and use-phase emissions. Results are compared against a natural gas boiler as the reference case. Under continued carbon price escalation of $15/tCO2e annually (CP15), this study highlights the effectiveness of an advanced hybrid concentrated solar thermal system with electric thermal energy storage (CST E-TES), as it achieves high round-trip efficiencies of up to 90 %, the lowest levelized cost of heat among renewable options at 19 $/MWht and 83 % lower emissions than natural gas.