Underground Compressed-Air Storage for Electric Utility Load Leveling

Abstract

This paper discusses underground compressed-air storage reservoirs with respect to leveling the loads on electric utilities and compares them with natural-gas storage systems. Rapid injection and removal of air on a daily cycle is a major problem. Mined hard-rock caverns, solution-mined salt cavities, fixed-volume porous sand reservoirs, and aquifers are analyzed for possible use. Introduction Every energy supplier has a problem with matching supply to demand. In the natural gas industry this is basically a seasonal situation, with relatively low summer usage and high winter needs, which has led to the development of underground storage of natural gas in depleted gas fields or aquifer basins near demand centers. Gas is injected in the storage reservoir at a steady rate for 6 to 8 months and released at several times the injection rate during the cold winter months. Once a storage field has been developed and filled with gas, subsequent injected gas can be recovered totally. Energy-wise, the only loss is incurred by the compression system needed for injecting the gas, which is a small fraction of the energy of the gas. The electrical utility industry's daily load fluctuation compares with the annual load variation of the natural gas industry. A typical weekly load curve, taken from The 1970 National Power Survey, is shown in Fig. 1. Electrical energy cannot be stored economically with present technology. Therefore, plans for augmenting electrical supply during peak day hours and for consuming energy during low-load night hours and weekends are welcomed. Several highly successful pumped-storage facilities exist for performing this function. pumped-storage facilities exist for performing this function. In such units, water is pumped from a low-level to a higher-level reservoir at night. Water flow is reversed the next day with pumps becoming turbines and motors acting as generators. One of the largest operations is located at Ludington, MI, a $300 million installation with daily energy storage and delivery of 15 million kw-hr. About 70% of the pumping energy is recovered as useful peakload electrical energy. This daily energy storage equals about 150 MMcf natural gas, at a 34% generating efficiency. On an energy basis, therefore, electrical utilities must store relatively modest amounts, but must cycle the storage facility 250 times per year. Many electrical utility systems do not have favorable topographical formations for installing a pumped-storage station. An energy-storing alternative for the diurnal cycle involves compressing air at night and expanding it during peak-load hours. Before expansion, the air can be heated by combustion of a hydrocarbon fuel, greatly increasing its volume and work load. In such a scheme, more electrical energy is delivered from the storage facility than is consumed, at the expense of fuel energy. Fundamentally, the compressed-air-storage generating plant is a gas turbine cycle, with 12 hours separating the plant is a gas turbine cycle, with 12 hours separating the compression and expansion stages. This has significant advantages in equipment size, fuel costs, heat rate for the gas turbine unit, and capital costs. Of course, the disadvantage is the huge volume of compressed air storage needed that is economical, reliable, and available at the desired location. This paper examines the role and characteristics of various types of underground reservoirs as they might be used in a compressed-air-storage electric generating plant. JPT P. 1656