Thermal energy storage (TES) is gaining interest and traction as a crucial enabler of reliable, secure, and flexible energy systems. The array of in-front-of-the-meter TES technologies under development highlights the potential for demand shifting, variable supply integration, sector integration, network management, and seasonal storage.
As the energy transition unfolds worldwide, stakeholders across the vast power system are scrambling to identify solutions that will sustainably uphold its most critical attributes: energy security, affordability, and environmental benefit. Driving this quest is a complex set of factors, foremost among them, perhaps, the urgency to more smoothly and economically incorporate the increasing share of variable renewables.
While the energy storage sector has burgeoned as a promising solution, its stunning growth has centered mainly on battery storage—storage using chemical energy—given its applicational versatility in the power, buildings, and transport sectors. Stakeholders generally recognize, however, that battery storage faces cost limitations related to their shorter lifespans and difficulty in leveraging economies of scale in large volumes over a prolonged period. Safety and supply chain geopolitics are also growing concerns. Pumped storage hydropower, which relies on storage using water’s potential energy, may provide larger output and variability, but costs are dependent on terrain, and few suitable locations remain. And while hydrogen energy storage systems have received much attention of late, large-scale projects remain in the development phase, and their high costs remain a concern.
As climate change ambitions size up—and decarbonized outlooks increasingly encapsulate and seek to couple multiple industries—a notable spate of activity is springing up around thermal energy storage (TES) systems, a set of energy storage technologies that leverage the temporary storage of energy by heating or cooling as a storage medium. While TES has so far burgeoned mostly behind the meter to store low-temperature heat generated either through electrically powered heat pumps or by onsite solar thermal plants, demonstrations suggest growing potential for their wider commercial-scale use in the power sector. These include hybridized installations at power plants, including at fossil, nuclear, and renewables facilities, to help mitigate dips and spikes in output and enable capacity firming, as well as standalone installations on the grid, where TES could enable load shifting.
Heat Storage: The Broader Context
According to the International Renewable Energy Agency (IRENA), a “growing business case lies ahead of TES technologies.” While IRENA has confirmed 234 GWh of TES already existed at the end of 2019, it projects that investments in the range of $12.8 billion to $27.2 billion will be sunk into TES over the next decade, potentially expanding that capacity threefold to at least 800 GWh.
TES’s biggest allure, it said, is to provide flexibility when considered from a “whole systems” approach. “TES technologies offer unique benefits, such as helping to decouple of heating and cooling demand from immediate power generation and supply availability. The resulting flexibility allows far greater reliance on variable renewable sources, such as solar and wind power,” IRENA explained. “TES thereby reduces the need for costly grid reinforcements, helps to balance seasonal demand and supports the shift to a predominantly renewable-based energy system.”
But despite its good posture, TES’s unique capacities lack the general market awareness given to other energy storage forms because many of its varying technologies are still in the development phase. That may require policy intervention to ensure energy policymaking can coherently support TES market competition, and TES research and innovation, IRENA suggested. TES technologies generally fall into four distinct groups based on their underlying principle of operation: sensible heat storage, latent heat storage, thermochemical heat storage, and mechanical-thermal coupled systems (Figure 1).
Sensible heat storage, the most commonly deployed and commercially advanced type of TES, essentially stores thermal energy by heating or cooling a storage medium (liquid or solid) without changing its phase. “The amount of stored energy is proportional to the temperature change (rise or fall) on charging, within the operational temperature range, and the thermal capacity of the material,” IRENA says. Examples include tank thermal energy storage, using water as a storage medium; solid-state thermal storage, such as with ceramic bricks, rocks, concrete, and packed beds; liquid (or molten) salts; and underground thermal energy storage. Latent heat storage involves phase-change materials (PCMs), which essentially enable change to a material’s phase (typically from a solid to a liquid) to store thermal energy. A prominent example is ice-thermal storage.
Thermochemical heat storage, which has a higher energy density than sensible and latent heat storage, involves two technology families: reversible reaction-based storage and sorption-based energy storage. “Thermochemical systems without sorption are based on a reversible reaction of two separate chemical substances where a high amount of energy is generated as a result of an exothermic synthesis reaction. In a sorption process, heat is stored by breaking the binding force between the sorbent and the sorbate in terms of chemical potential,” IRENA explains. Examples include chemical looping, salt hydration, and adsorption systems.
Finally, mechanical TES systems involve TES systems coupled with mechanical energy storage technologies, such as compressed air energy storage (CAES) and liquid air energy storage (LAES).
Promising TES Technologies for the Power Sector
POWER’s analysis suggests a broad range of TES technologies are currently under development or already in use for power plant and grid integration. Here are just a few prominent examples.
Liquid Salts. The most widely commercially applied TES technology involves using molten salts at high-temperature concentrated solar power (CSP) stations. At the end of 2019, the estimated worldwide power generation capacity from CSP molten salt systems was 21 GWh (60 GWhth, with an average duration of seven hours). However, molten salt hybrid configurations are also being explored at solar PV and wind configurations, as part of an integration with natural gas combustion, and even to improve the efficiency of existing coal and advanced nuclear plants.
German entities RWE and RWTH Aachen University, for example, in 2019 kicked off work to integrate a molten salt system heated (to 600C) with surplus renewable power to create steam, which is then fed into a turbine at an existing coal-fired plant in the Rhenish lignite area. TerraPower’s Natrium, which is set to demonstrate a 345-MWe sodium fast reactor near Pacificorp’s Naughton power plant in Wyoming under the U.S. Department of Energy’s (DOE’s) Advanced Reactor Demonstration Program within seven years, will notably use a nitrate-salt molten salt system that its developers claim has the potential to “boost the system’s output to 500 MWe of power for more than five and a half hours when needed.” The system derives its technology from a system of similar scale that is employed at the 280-MW Solana CSP plant in Arizona. Nitrate-salt storage system designs are also proposed for fluoride-salt-cooled high-temperature reactors with solid fuel and liquid salt coolants, and molten salt reactors with fuel dissolved in the salt.
Malta, a developer of pumped heat energy storage technology, is meanwhile working with New Brunswick, Canada–based NB Power to deliver a 1,000-MWh facility based on its molten salt integrated storage system by 2024. The facility is currently slated to be one of the largest of its kind in the world. Malta, notably, also teamed with engineering, construction, and project management industry giant Bechtel to pursue, develop, and deploy Malta’s 10-150-plus hour energy storage technology in a variety of grid-scale applications.
Several other promising systems are also under development. One much-watched technology is Pintail Power’s liquid salt combined cycle technology, which synergistically integrates molten salt—eutectic salt—with combustion turbine exhaust heat. The technology offers new prospects for hybrid power configurations, including to store and reduce curtailment of renewable energy, or use nuclear power–produced hydrogen to fuel the system.
Heat Transfer Oils. Another innovative medium derived from the CSP sector—specifically from parabolic trough CSP plants—involves using heat transfer oils such as Eastman’s Therminol-66. One example is a 16.6-MW CSP project that forms part of the Brønderslev hybrid solar-biomass plant in Denmark. Therminol-66 (along with ethylene glycol and alumina beads) are slated for testing at Idaho National Laboratory’s experimental Thermal Energy Distribution System, a project that in December 2020 began evaluating the interoperability of nuclear reactors, energy storage, and ancillary processes in a real-world setting.
Crushed Rock Heat Storage. TES systems that use crushed rock are gaining prominence throughout the power space mainly for their low-cost ability to provide large-scale heat storage. Since its 2019 launch of a 30-MW/130-MWh Electric Thermal Energy Storage (ETES) pilot (with a 5.4-MW resistive heater) in Hamburg (Figure 2), for example, Siemens Gamesa Renewable Energy (SGRE) says it has racked up interest in the system that has a temperature range of 180C to 750C. SGRE says its technology, which essentially draws power from the grid to heat volcanic stones, can be converted back into power using a 1.4-MW steam turbine generator and produce power for up to 24 hours. The approach could give thermal plants a second life, it says.
On the nuclear front, Westinghouse is exploring a system for new-build pressurized water reactors where steam is used to heat oil that in turn transfers it to concrete in prefabricated boxes. The solution uses “thin plates with narrow gaps” to create “huge surface area relative to volume and minimizes oil fraction.” In South Korea, researchers have designed a nuclear heat storage and recovery system, interfaced with the APR1400 reactor plant. The system comprises a packed bed of Hornfels rock, with heat supplied by Therminol-66 oil. The process cycle essentially involves diverting steam from the APR1400 steam cycle upstream of the high-pressure turbine, condensing and cooling it in heat exchangers, and then transporting the hot oil offsite to the packed bed configuration for storage.
Another prominent example is a project launched this June by the New York Power Authority and the Electric Power Research Institute (EPRI) to explore Israeli firm Brenmiller Energy’s high-temperature crushed rock TES system (Figure 3) in a range of fossil generation assets. A Brenmiller 4-MW/23-MWh system was also installed at an Enel combined cycle gas turbine plant in Italy, between the gas turbine and steam turbine. “The bGen is charged with residual low-value steam and discharges superheated steam at peak tariff hours to allow energy shifting, faster ramp-up and other revenue streams,” said Brenmiller.
Concrete Thermal Energy Storage. EPRI and Colorado-headquartered Storworks Power (a company formerly known as Bright Energy Storage) are exploring a technology that uses concrete to store energy generated by thermal power facilities, including fossil, nuclear, and CSP plants. Recent lab tests have validated the design, which essentially uses large concrete blocks that are stacked in a location near the power plant and heats them through tubes embedded in the blocks with redirected plant-produced steam when the plant’s output is not needed by the grid.
“When plant power production needs to be increased again, heated feedwater from the plant is pumped into the tubes and converted to superheated steam for power generation at a separate steam turbine. At the same time, steam generated by the power plant is diverted back to the plant’s main turbine to generate additional output,” EPRI said. “This approach can extend the time for the plant to run at full load, boosting efficiency and reducing damage that can result from cycling up and down and other dynamic modes.”
EPRI and Storworks Power are now working with Southern Co. and engineering company United E&C to demonstrate an optimized design at Alabama Power’s Plant Gaston (Figure 4) in a project backed with a $4 million DOE award. Construction kicked off in September 2021 and the 10-MWh-e demonstration is expected to wrap up by the end of 2022.
EPRI suggests that because the technology uses “readily available, cheap concrete,” it can potentially enable energy storage at capital costs of less than $100/kWh—well below the capital costs of lithium-ion batteries. “At about $65 per ton, concrete is less than 10% of the cost of the molten salts currently used for thermal storage,” said EPRI Principal Technical Leader Scott Hume. “With heat losses of about 1% per day, concrete systems can potentially provide several days of storage, which is what’s needed in wind- and solar-dominated energy markets. That’s well above the four hours of storage possible with today’s grid-scale battery storage systems. In the future, several days of storage will be needed to shift solar and wind energy from periods of excess production to periods of limited production.”
Heated Sand. Researchers at the National Renewable Energy Laboratory (NREL) in late August announced they are in the “late stages” of prototype testing a TES that uses inexpensive silica sand. The “ENDURING” project, for which Babcock & Wilcox holds an exclusive intellectual property option agreement, essentially feeds sand particles through an array of electric resistive heating elements to heat them to 1,200C—“imagine pouring sand through a giant toaster,” NREL told POWER—and gravity-feeds them into insulated silos for thermal energy storage. The baseline system can store 26,000 MWh, it said. During periods of high power demand, the hot particles are gravity-fed through a heat exchanger, heating and pressurizing a working gas inside to drive the turbomachinery and spin generators that create electricity for the grid.
Phase Change Technology. Maine-based Peregrine Turbine Technologies (PTT), Australian-based MGA Thermal, and Maine-based Cianbro Corp. are working on a first-of-kind 1-MW/16.5-MWh TES system at an existing Maine solar PV installation that will integrate miscibility gap alloy phase change technology and PTT’s supercritical carbon dioxide turbomachinery. As Robert Brooks, PTT chief business development officer and co-founder, told POWER in November, the TES is not intended to compete with batteries for immediacy, even though it may be less expensive than batteries when the dispatch duration is four hours or more at rated output. “Due to the capacity costs, there will always be some duration where the TES offers a lower cost than batteries. If fast-ramp discharge capacity is desired, then the lowest cost solution would be a [lithium]-ion/TES hybrid solution where batteries are used for immediacy and frequency support and the TES provides capacity,” he explained. The driver of adoption for TES technology will less likely be its cost in dollars per MWh, “but rather its operating flexibility for deep cycling to capture revenue, its extended run time capacities, and the potential to capture capacity that is poorly utilized,” Brooks suggested.
Offering a different approach to PCMs, Australian firm 1414 Degrees is developing SiBox, a TES based on molten silicon that is heated with surplus power (stored at 1,414C—hence the company’s name). “The key breakthrough of SiBox is the combination of a unique PCM and a containment design which harnesses the latent heat properties of silicon for thermal energy storage, while solving key challenges such as preventing oxidation, managing volume change during melting and solidification, and managing inter-reaction with containment materials,” the company said in October. The company recently garnered A$2 million in investment from Woodside for its planned demonstration of a 1 MWh demonstration module. If the demonstration, which is scheduled to be commissioned in 2023, validates the technology, 1414 Degrees plans to build a 75-MWh multimodule project.
CAES and LAES. Systems utilizing mechanical-thermal coupled systems are also notably powering through the demonstration stage. Canadian firm Hydrostor, developer of the advanced CAES (A-CAES) technology, this year unveiled two giant projects that could come online by 2026 to bolster California’s quest for reliability, particularly after the Diablo Canyon Nuclear Plant shuts down. In November, it filed for state certification of the 400-MW, 8-hour long-duration Pecho Energy Storage Center. Hydrostor is meanwhile still developing the even larger 500-MW/4,000-MWh Gem A-CAES project in Kern County, California. It is also developing a 200-MW project with Australian utility Energy Estate to support reliability in New South Wales.
Meanwhile, after years of testing and demonstration, Highview Power, developer of a LAES cryogenic energy storage system, is building its first commercial facility. The 50-MW/250-MWh CRYOBattery facility in Carrington Village, just outside Manchester in the UK, is slated to begin operations in 2022. As CEO Javier Cavada told POWER earlier this year, growing interest in the technology is pegged to the system’s versatility. “Our technology has big masses of rotating equipment—from the compressors to the air turbine to the generator—that provide inertia that’s synchronized with the grid, providing reactive power, and providing balancing capabilities to the grid,” he said.