Updated: Jul 10, 2020
As the quantity and proportion of renewable energy on many developed electricity grids increases, grid operators face a growing problem of integrating intermittent, uncertain, energy sources with conventional power to meet electricity demand on a minute-by-minute basis. The operator has a number of potential tools in his box, from “spilling” excess renewable power in times of high supply to providing short term gas-powered backup generation in times of shortage to, in the much longer term, demand side management.
The major solutions to this issue in the relatively short term are seen to be various forms of energy storage. If you have already read the earlier “insight” papers in this series, you will understand why we need large scale storage on many European and N American grids as the amount of renewable generation on these systems increases.
The various small- and grid-scale storage methods which can be used, together with their size and output, are shown in the figure 1 below.
Figure 1: Classification of electric energy storage technologies (SNL, 2013)
These methods are typically classified by their power ratings (expressed in MW) on the x-axis and their potential output (expressed in MWh or duration of delivery at their rated output) on the y-axis. They range in size from small scale supercapacitors and batteries at the kW end to the only two current technologies which have GW scale, namely pumped hydro and CAES.
Pumped hydroelectric energy storage (PHES) is the most widely adopted utility-scale electricity storage technology and provides the most mature and commercially available solution to bulk energy storage. PHES can supply flexible generation with spinning and standing reserves proving both up and down regulation, while the quick start capability makes it suitable for black starts. PHES facilities provide large electrical capacity, with low operation and maintenance costs, long asset life (50-100 years) and high reliability. In addition, the levelized storage cost of electricity using PHES are typically much lower than other electricity storage technologies.
However, PHES is immensely disruptive and typically takes decades to plan and execute. It is a net user of power (despite having the potential to be profitable) and can be environmentally damaging as it affects large tracts of land both upstream and downstream of the dam.
This leaves Compressed Air Energy Storage (CAES) as a potential technology at this scale, which is capable of being developed in a relatively short period. CAES uses cheaper off-peak electrical energy to compress and store air in a large underground reservoir. The air is subsequently released to generate electric power by running air expanders/turbines when the output from renewable energy sources is reduced or electricity demand is high, effectively providing a buffer to manage swings in energy demand and supply.
There are two operating CAES plants, one at Huntorf in Germany where the 290 MW capacity plant was commissioned in 1978, and another 110 MW plant at McIntosh, Alabama in USA, which was constructed in 1991.
Hitherto, CAES has been confined to leached salt caverns and the option’s economic viability has been heavily dependent upon the price paid for the brine leached when creating the cavern, and the efficiency of the “round trip” process of getting air into and back out of the storage during operation.
So far, three types of CAES have been developed, at least to the concept stage, summarised in the diagram and the text below:
Figure 2: CAES development process (Zhou, Q. et. al., 2019)
Diabatic Compressed Air Energy Storage (D-CAES): the earliest development, where the air is compressed and stored at near ambient temperatures in the underground cavern. The heat generated during the compression phase is removed and not used again the process. When the air is released, it is warmed by the ignition of a fuel mixture in the turbine, both to avoid ice build-up in the machinery and to improve the efficiency of the power generating turbine. As you might expect, this form of CAES is not very efficient (typically 40 – 50% “round trip” efficiency) and requires an external source of fuel to run. Both the currently working systems are of this type. The Huntorf plant is shown schematically below:
Figure 3. structure of existing Huntorf CAES plant (Hoffeins, 1994)
Adiabatic CAES also termed Advanced Adiabatic CAES (AA-CAES): heat generated during compression is captured without intercooling and stored in a separate Thermal Energy Storage (TES) System. When energy is needed, the system is reversed and heat is added back to the air during the expansion phase, thus eliminating the need for external heat sources (i.e. fossil fuels). This is shown in figure 4 below:
Figure 4. Adiabatic Compressed Air Storage (A-CAES) process (Huang et al, 2017)
The adiabatic addition to “conventional” CAES shown in Figure 4 is not yet in operation, but any new build system would use this and would consist of four major components: motor driven compressors, air turbines/generator, the thermal energy storage (TES) system and an underground cavern for high pressure air storage. During off-peak hours ambient air is compressed and stored under pressure in the cavern. When electricity is required during peak load periods the pressurised air is released, heated up by the heat exchangers transferring heat from the TES, and then expanded in air turbines driving a generator for power generation. Both “conventional” and adiabatic CAES use little gas and have low carbon footprints.
Isothermal CAES: effective heat management remains one of the primary challenges when dealing with compression-based energy storage schemes. Isothermal CAES (I-CAES) attempts to achieve near-isothermal compression and expansion thus avoiding any external heat exchangers to compress and expand the air. Benefits include improved efficiency (~70-80%), operation at lower temperature (< 80 °C) and fuel-free operation. I-CAES systems are also still only at the development stage, however.
It is apparent that CAES has the scale, and the potential flexibility, to provide a valuable contribution to electricity grid balancing. The issues of efficiency, particularly of the TES part of the process, and hence the economic attractiveness of CAES are the aspects currently being studied. Thermal Energy Storage is inherently less efficient than electrical energy storage, and the optimisation of this part of the process is therefore receiving a good deal of attention.
Another fruitful area of study seems to be air storage locations; from hard rock caverns to undersea solutions, alternatives to the salt domes used hitherto are being researched.
Hoffeins, H. (1994) “Huntorf Air Storage Gas Turbine Power Plant,” Energy Supply - Brown Boveri Mittelungen, no. D GK 90 202 E.
Huang, Y, et.al. “Techno-economic modelling of large scale compressed air energy storage systems”, Energy Procedia 105 (2017) 4034 - 4039
SNL 2013: Sandia National Laboratories, DOE/EPRI 2013 Electricity Storage Handbook in Collaboration withNRECA, Report SAND2013-5131, July 2013.
Zhou, Q, et.al. “A review of thermal energy storage in compressed air storage system”, Energy 188 (2019) 115993