Turbines, Gas

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The aircraft gas turbine engine, developed more than sixty years ago, uses the principle of jet reaction and the turbine engine. The engine consists of three major elements: a compressor and a turbine expander, which are connected by a common shaft; and a combustor, located between the compressor and the turbine expander. The useful work of the engine is the difference between that produced by the turbine and that required by the compressor. For the simple cycle system shown in Figure 1, about twothirds of all the power produced by the turbine is used to drive the compressor.

Jet reaction used in the first steam-powered engine, the aeolipile, is attributed to Hero of Alexandria around the time of Christ. In his concept, a closed spherical vessel, mounted on bearings, carried steam from a cauldron with one or more people discharging tangentially at the vessel's periphery, and was driven around by the reaction of steam jets. According to the literature, the first gas turbine power plant patent was awarded to John Barber, an Englishman, in 1791. Intended to operate on distilled coal, wood, or oil, it incorporated an air compressor driven through chains and gears by a turbine operated by the combustion gases. It was actually built but never worked.

There was a steady increase in the number of gas-turbine patents after Barber's disclosure. However, the attempts of the early inventors to reduce them to practice was entirely unsuccessful.

The early inventors and engineers were frustrated in their efforts to achieve a workable gas turbine engine because of the inadequate performance of the components and the available materials. However, gas turbine engine technology has advanced rapidly since the 1940s. Thrust and shaft horsepower (hp) has increased more than a hundredfold while fuel consumption has been cut by more than 50 percent. Any future advances will again depend upon improving the performance of components and finding better materials.


Perhaps the first approach to the modern conception of the gas-turbine power plant was that described in a patent issued to Franz Stolze in 1872. The arrangement of the Stolze plant, shown in Figure 2, consisted of a multistage axial-flow air compressor coupled directly to a multistage reaction turbine. The high-pressure air leaving the compressor was heated in an externally fired combustion chamber and thereafter expanded in the multistage turbine. The Stolze plant was tested in 1900 and 1904, but the unit was unsuccessful. The lack of success was due primarily to the inefficiency of the axial-flow compressor, which was based on aerodynamics, a science that was in its early stages of development. The lack of aerodynamic information also led Charles Algernon Parsons, the inventor of the reaction steam turbine, to abandon the development of the axial-flow compressor in 1908 after building approximately thirty compressors of that type with little success.

Several experimental gas-turbine power plants were built in France from 1903 to 1906. Those power plants operated on a cycle similar to that of a modern gas-turbine power plant. The most significant unit had a multistage centrifugal compressor that consisted essentially of a stationary casing containing a rotating impeller. Because of material limitations, the temperature of the gases entering these turbines was limited to 554°C (1,030°F). The thermal efficiency of the unit (work output divided by heat supplied) was less than 3 percent, but the unit is noteworthy, however, because it was probably the first gas-turbine power plant to produce useful work. Its poor thermal efficiency was due to the low efficiencies of the compressors and the turbine, and also to the low turbine inlet temperature.

Brown Boveri is credited with building the first land-based gas turbine generating unit. Rated at 4 MW, it was installed in Switzerland in 1939. Leaders in the development of the aviation gas turbine during the Second World War included: Hans von Ohain (Germany), Frank Whittle (England), and Reinout Kroon (United States). Thus, combining the technology derived for aviation gas turbines with the experience of using turbines in the chemical industry, the birth of gas turbines for power generation started in the United States in 1945 with the development of a 2,000-hp gas turbine set that consisted of a compressor, twelve combustors, a turbine, and a single reduction gear. This turbine had a thermal efficiency of 18 percent. By 1949, land-based gas turbines in the United States had an output of 3.5 MW with a thermal efficiency of 26 percent at a firing temperature of 760°C (1,400°F).


Aircraft and land-based turbines have different performance criteria. Aircraft turbine engine performance is measured in terms of output, efficiency, and weight. The most significant parameter in establishing engine output (thrust or shaft hp) is turbine inlet temperature. Power output is extremely dependent on turbine inlet temperature. For example, an engine operating at 1,340°C (2,500°F) would produce more than over two and one-half times the output of an engine operating at 815°C (1,500°F). Engine efficiency, which is next in importance to engine output, is determined largely by overall engine or cycle pressure ratio. Increasing the pressure ratio from one to twenty reduces the fuel consumption by approximately 25 percent. Engine weight is affected most by turbine inlet temperatures (which acts to reduce the physical size of the engine) and by state-of-the-art materials technology that sets the temperature criteria.

During the Second World War, centrifugal compressors were used in early British and American fighter aircraft. As power requirements grew, it became clear that the axial flow compressor was more suitable for large engines because they can produce higher pressure ratios at higher efficiencies than centrifugal compressors, and a much larger flow rate is possible for a given frontal area. Today, the axial flow machine dominates the field for large power generation, and the centrifugal compressor is restricted to machines where the flow is too small to be used efficiently by axial blading.

For land-based gas turbines, the overall plant output, efficiency, emissions, and reliability are the important variables. In a gas turbine, the processes of compression, combustion, and expansion do not occur in a single component, as they do in a diesel engine. They occur in components that can be developed separately. Therefore, other technologies and components can be added as needed to the basic components, or entirely new components can be substituted.

Advanced two- and three-dimensional computer analysis methods are used today in the analyses of all critical components to verify aerodynamic, heat transfer, and mechanical performance. Additionally, the reduction of leakage paths in the compressor, as well as in the gas turbine expander, results in further plant efficiency improvements. At the compressor inlet, an advanced inlet flow design improves efficiency by reducing pressure loss. Rotor air cooler heat utilization and advanced blade and vane cooling are also used.

Several advanced turbine technologies may be applied to the gas turbine expander. These include the application of single crystal and ceramic components to increase material operating temperatures and reduce turbine cooling requirements, and active blade tip clearance control to minimize tip leakages and improve turbine efficiency. The objective of the latter scheme is to maintain large tip clearance at start-up and reduce them to minimum acceptable values when the engine has reached steady-state operating conditions.


As an alternative to raising firing temperature, overall power plant performance can be improved by modifications to the cycle. Combining a land-based simple cycle gas turbine with a steam turbine results in a combined cycle that is superior in performance to a simple gas turbine cycle or a simple cycle steam turbine considered separately. This is due to utilizing waste heat from the gas turbine cycle. By 1999, land-based sample cycle gas turbine efficiencies had improved from 18 percent to more than 42 percent, with the better combined cycles reaching 58 percent, and the ones in development likely to exceed 60 percent. Combined cycle efficiency improvements have followed the general advance in gas turbine technology reflected in the rising inlet temperature trend shown in Figure 3, which, in turn, was made possible by advances in components and materials.

Gas turbines can operate in open or closed cycles. In a simple cycle (also known as an open cycle), clean atmospheric air is continuously drawn into the compressor. Energy is added by the combustion of fuel with the air. Products of combustion are expanded through the turbine and exhausted to the atmosphere. In a closed cycle, the working fluid is continuously circulated through the compressor, turbine, and heat exchangers. The disadvantage of the closed cycle (also known as the indirect cycle), and the reason why there are only a few in operation, is the need for an external heating system. That is an expensive addition and lowers efficiency.

Most current technology gas turbine engines use air to cool the turbine vanes and rotors. This allows the turbine inlet temperature to be increased beyond the temperature at which the turbine material can be used without cooling, thus increasing the cycle efficiency and the power output. However, the cooling air itself is a detriment to cycle efficiency. By using closed-loop steam cooling, a new concept, the cooling air mixing loss mechanisms can be largely eliminated, while still maintaining turbine material temperatures at an acceptable level. An additional benefit of closed-loop cooling is that more compressor delivery air is available for the lean premix combustion. The result is lower flame temperature and reduced oxides of nitrogen (NOx) emission. In combined cycles, the steam used for cooling the gas turbine hot parts is taken from the steam bottoming cycle, then returned to the bottoming cycle after it has absorbed heat in the closed-loop steam cooling system. For an advanced bottoming steam cycle, closed-loop steam cooling uses reheat steam from the exit of the high-pressure steam turbine to cool the gas turbine vane casing and rotor. The steam is passed through passageways within the vane and rotor assemblies and through the vanes and rotors themselves, then collected and sent back to the steam cycle intermediate-pressure steam turbine as hot reheat steam.

Several of the gas turbine cycle options discussed in this section (intercooling, recuperation, and reheat) are illustrated in Figure 4. These cycle options can be applied singly or in various combinations with other cycles to improve thermal efficiency. Other possible cycle concepts that are discussed include thermo-chemical recuperation, partial oxidation, use of a humid air turbine, and use of fuel cells.

The most typical arrangement for compressor inter-cooling involves removing the compressor air flow halfway through the compressor temperature rise, sending it through an air-to-water heat exchanger, and returning it to the compressor for further compression to combustor inlet pressure. The heat removed from the compressor air flow by the intercooler is rejected to the atmosphere because the heat is usually at too low a temperature to be of use to the cycle.

Another intercooling application is to spray water droplets into the compressor. As the air is compressed and increases in temperature, the water evaporates and absorbs heat. This results in a continuous cooling of the compressor. Note that for this concept the heat absorbed by the water is also rejected to the atmosphere. This water is never condensed by the cycle, but instead exhausted with the stack gases as low-pressure steam.

Compressor intercooling reduces the compressor work because it compresses the gas at a lower average temperature. The gas and steam turbines produce approximately the same output as in the nonintercooled case, so the overall cycle output is increased. However, since the compressor exit temperature is lowered, the amount of fuel that must be added to reach a given turbine inlet temperature is greater than that for the nonintercooled case. Intercooling adds output at approximately the simple cycle efficiency—the ratio of the amount of compressor work saved to the amount of extra fuel energy added is about equal to the simple cycle efficiency. Since combined cycle efficiencies are significantly greater than simple cycle efficiencies, the additional output at simple cycle efficiency for the intercooled case usually reduces the combined cycle net plant efficiency.

In recuperative cycles, turbine exhaust heat is recovered and returned to the gas turbine combustor, usually through a heat exchange between the turbine exhaust gases and the compressor exit airflow. The discharge from the compressor exit is piped to an exhaust gas-to-air heat exchanger located aft of the gas turbine. The air is then heated by the turbine exhaust and returned to the combustor. Since the resulting combustor air inlet temperature is increased above that of the nonrecuperated cycle, less fuel is required to heat the air to a given turbine inlet temperature. Because the turbine work and the compressor work are approximately the same as in the nonrecuperated cycle, the decrease in fuel flow results in an increase in thermal efficiency. For combined cycles the efficiency is also increased, because the gas turbine recovers the recuperated heat at the simple cycle efficiency, which is larger than the 30 to 35 percent thermal efficiency of a bottoming steam cycle, which recovers this heat in the nonrecuperated case. Since recuperative cycles return exhaust energy to the gas turbine, less energy is available to the steam cycle, and the resulting steam turbine output is lower than that of the baseline configuration. Even though the gas turbine output is approximately the same as in the baseline cycle (minus losses in the recuperation system), recuperative cycles carry a significant output penalty because of reduced steam turbine work, which is proportional to the amount of recuperation performed.

From a simple cycle standpoint, the combination of intercooling with recuperation eliminates the problem of the reduced combustor inlet temperature associated with intercooled cycles. The simple cycle then gets the benefit of the reduced compressor work and, at all but high pressure ratios, actually has a higher burner inlet temperature than the corresponding nonintercooled, nonrecuperated cycle. This results in a dramatic increase in the simple cycle efficiency.

Reheat gas turbines utilize a sequential combustion process in which the air is compressed, combusted, and expanded in a turbine to some pressure significantly greater than ambient, combusted again in a second combustor, and finally expanded by a second turbine to near ambient pressure. For a fixed turbine rotor inlet temperature limit, the simple cycle efficiency is increased for a reheat gas turbine compared to a nonreheat cycle operating at a pressure ratio corresponding to the second combustor's operating pressure. This is because the reheat cycle performs some of its combustion and expansion at a higher pressure ratio.

Thermochemical recuperation (TCR), also known as chemical recuperation, has been under evaluation for several years as a promising approach to increase power generation efficiencies. In a TCR power plant, a portion of the stack exhaust gas is removed from the stack, compressed, mixed with natural gas fuel, heated with exhaust heat from the gas turbine, and mixed with the air compressor discharge as it enters the combustor. As the mixture of natural gas and flue gas is heated by the gas turbine exhaust, a chemical reaction occurs between the methane in the fuel and the carbon dioxide and water in the flue gas. If this reaction occurs in the presence of a nickel-based catalyst, hydrogen and carbon monoxide are produced. For complete conversion of the methane, the effective fuel heating value is increased. Therefore, the natural gas/flue gas mixture absorbs heat thermally and chemically, resulting in a larger potential recuperation of exhaust energy than could be obtained by conventional recuperation, which recovers energy by heat alone. In fact, with full conversion of the natural gas fuel to hydrogen and carbon monoxide, up to twice the energy recuperated by the standard recuperative cycle may be recovered.

Partial oxidation (PO) has also been proposed as a means to increase the performance of gas turbine power systems. PO is a commercial process used by the process industries to generate syngases from hydrocarbons, but under conditions differing from those in power generation applications. In this concept, a high-pressure, low-heating-value fuel gas is generated by partially combusting fuel with air. This fuel gas is expanded in a high-pressure turbine prior to being burned in a lower-pressure, conventional gas turbine. This process reduces the specific air requirements of the power system and increases the power output. PO has several potential advantages over conventional cycles or reheat cycles: lower specific air consumption and reduced air compressor work; increased power plant thermal efficiency; and potentially lower NOx emissions with improved combustion stability.

One difficulty associated with waste heat recovery systems is the satisfactory use of low grade heat to reduce stack losses. The humid air turbine (HAT), shown in Figure 5, uses a concept that should be considered on how to improve the use of low-grade heat. Warm waste is brought into contact with the compressor delivery air in a saturator tower to increase the moisture content and increase the total mass flow of the gases entering the turbine without significantly increasing the power demand from the compressor. Thus low-grade heat is made available for the direct production of useful power. Also, the high moisture content of the fuel gas helps to control NOx production during the combustion process.

Over a number of years, fuel cells have promised a new way to generate electricity and heat from fossil fuels using ion-exchange mechanisms. Fuel cells are categorized by operating temperature and the type of electrolyte they use. Each technology has its own operating characteristics such as size, power, density, and system configurations.

One concept, a solid oxide fuel cell (SOFC) supplied with natural gas and preheated oxidant air, produces direct-current electric power and an exhaust gas with a temperature of 850° to 925°C (1,560° to 1,700°F). In this hybrid system, the fuel cell contributes about 75 percent of the electric output, while the gas turbines contribute the remaining 25 percent. The SOFC exhaust can be expanded directly by a gas turbine with no need for an additional combustor. SOFC technology can be applied in a variety of ways to configure both power and combined heat and power (CHP) systems to operate with a range of electric generation efficiencies. An atmospheric pressure SOFC cycle, capable of economic efficiencies in the 45 to 50 percent range, can be the basis for a simple, reliable CHP system. Intergating with a gas turbine to form an atmospheric hybrid system, the simplicity of the atmospheric-pressure SOFC technology is retained, and moderately high efficiencies in the 50 to 55 percent range can be achieved in either power or CHP systems.

The pressurized hybrid cycle provides the basis for the high electric efficiency power system. Applying conventional gas turbine technology, power system efficiencies in the 55 to 60 percent range can be achieved. When the pressurized hybrid system is based on a more complex turbine cycle—such as one that is intercooled, reheated, and recuperated—electric efficiencies of 70 percent or higher are projected.


The majority of today's turbines are fueled with natural gas or No. 2 distillate oil. Recently there has been increased interest in the burning of nonstandard liquid fuel oils or applications where fuel treatment is desirable. Gas turbines have been engineered to accommodate a wide spectrum of fuels. Over the years, units have been equipped to burn liquid fuels, including naphtha; various grades of distillate, crude oils, and residual oils; and blended, coal-derived liquids. Many of these nonstandard fuels require special provisions. For example, light fuels like naphtha require modifications to the fuel handling system to address high volatility and poor lubricity properties.

The need for heating, water washing, and the use of additives must be addressed when moving from the distillates toward the residuals. Fuel contaminants such as vanadium, sodium, potassium, and lead must be controlled to achieve acceptable turbine parts life. The same contaminants also can be introduced by the inlet air or by water/steam injection, and the combined effects from all sources must be considered.

The final decision as to which fuel type to use depends on several economic factors, including delivered price, cost of treatment, cost of modifying the fuel handling system, and increased maintenance costs associated with the grade of fuel. With careful attention paid to the fuel treatment process and the handling and operating practices at the installation, gas turbines can burn a wide range of liquid fuels. The ultimate decision on the burning of any fuel, including those fuel oils that require treatment, is generally an economic one.

Due to an estimated global recoverable reserve of more than 400 years of coal that can be used to generate electricity, future power generation systems must be designed to include coal. Today there are a number of gasification technologies available or being demonstrated at commercial capacity that are appropriate for power generation. Most of the development effort has been in the area of gasifiers that can be used in gasification combined cycle (GCC) applications. Other coal-fueled concepts under development include first- and second-generation pressurized fluidized bed (PFBC), and the indirect coal-fired case already discussed as a closed cycle.

Gasification is the reaction of fuel with oxygen, steam, and CO2 to generate a fuel gas and low-residue carbon char. This char differentiates gasification from other technologies that burn residual char separately or apply char as a by-product. The gasification fuel gas is composed primarily of hydrogen and carbon oxides as well as methane, water vapor, and nitrogen. Generic classes of gasifiers that can be used in a GCC are moving bed, fluidized bed, and entrained flow.

GCC integrates two technologies: the manufacture of a clean-burning synthesis gas (syngas), and the use of that gas to produce electricity in a combined cycle power generation system. Primary inputs are hydrocarbon feeds (fuels), air, chemical additives, and water; primary GCC outputs are electricity (generated within the power block that contains a gas turbine, steam turbine, and a heat recovery steam generator), syngas, and sulfur by-products, waste, and flue gas. The flows that integrate the subsystems include auxiliary power for an air separation unit and gasifier; air and nitrogen between an air separator and the gas turbine; heat from gasifier gas coolers to generate steam for the steam cycle; and steam to the gas turbine for NOx control.

Worldwide there are about thirty major current and planned GCC projects. Within the United States, the first GCC placed into commercial service, and operated from 1984 to 1989, was the 100-MW Cool Water coal gasification plant near Daggett, California.

Most commercial-size gasification projects have used oxygen rather than air as the oxidant for the gasifiers. Recent GCC evaluations have looked at using the gas turbine air compressor to supply air for the air separation unit. Typically this air stream is sent to a high-pressure air separator unit, which produces oxygen for gasification and high-pressure nitrogen for gas turbine NOx control. The diluent nitrogen lowers the flame temperature and therefore lowers the NOx.

Through Clean Coal Technology programs, the U.S. Department of Energy (DOE) is supporting several GCC demonstration projects that range in capacity from 100 to 262 MW. One of these plants is fueled by an advanced air-blown gasifier technology, and two of the projects will demonstrate energy-saving hot-gas cleanup systems for removal of sulfur and particulates. In Europe there are several commercial-size GCC demonstration plants in operation or under construction, ranging in size from 250 to 500 MW.

In a first-generation PFBC plant, the PFBC is used as the gas turbine combustor. For this application, the temperature to the gas turbine is limited to a bed temperature of about 870°C (1,600°F). This temperature level limits the effectiveness of this cycle as a coal-fired alternative.

In second-generation PFBC, a topping combustor is used to raise the turbine rotor inlet temperature to state-of-the-art levels. Pulverized coal is fed to a partial-gasifier unit that operates about 870° to 925°C (1,600° to 1,700°F) to produce a low heating value fuel gas and combustible char. The char is burned in the PFBC. The fuel gas, after filtration, is piped back to the gas turbine, along with the PFBC exhaust.

Fuel gas cleaning systems are being developed to fulfill two main functions: controlling the environmental emissions from the plant, and protecting downstream equipment from degraded performance. The fuel gas cleaning system also protects the gas turbine from corrosion, erosion, and deposition damage. Conventional GCC fuel gas cleaning systems, designated as cold gas cleaning, operate at temperatures of less than 315°C (600°F). Alternative technologies for fuel gas cleaning, which operate at considerably higher temperatures, are under development because of potential power plant performance benefits.

A biomass power generation industry is emerging that can provide substantial quantities of feedstock such as sugarcane residue (bagasse), sweet sorghum, rice straw, and switchgrass, as well as various wood byproducts. Today some of these residues are burned to generate power using a steam boiler and a steam turbine. However, operating problems result from ash agglomeration and deposition. Also, plant thermal efficiencies are relatively low, less than 30 percent, and in a number of plants less than 20 percent. The U.S. DOE has supported the development of biomassfueled gasification systems that can be integrated into a combined cycle power plant and thereby obtain thermal efficiencies of greater than 40 percent.

Coal gasification is fuel flexible so that the process can use the most available feedstock at the best price. Gasifiers have successfully gasified heavy fuel oil and combinations of oil and waste gas. Other possible gasification feedstock includes petroleum coke, trash, used tires, and sewage sludge. Various combinations of feedstocks and coal have been successfully gasified.

Orimulsion is a relatively new fuel that is available for the gasification process. Orimulsion is an emulsified fuel, a mixture of natural bitumen (referred to as Orinoco-oil), water (about 30%), and a small quantity of surface active agents. Abundant Orinoco-oil reserves lie under the ground in the northern part of Venezuela.


As discussed, the efficiency of a gas turbine cycle is limited by the ability of the combustion chamber and early turbine states to continuously operate at high temperatures. In 1992, the DOE started the Advanced Turbine Systems (ATS) Program that combined the resources of the government, major turbine manufactures, and universities to advance gas turbine technology and to develop systems for the twenty-first century. As pilot projects, two simple cycle industrial gas turbines are being developed for distributed generation and industrial and cogeneration markets, and two combined cycle gas turbines for use in large, baseload, central station, electric power generation markets.


Looking to the future, the Japanese government is sponsoring the World Energy Network (WE-NET) Program through its New Energy and Industrial Technology Development Organization (NEDO). WE-NET is a twenty-eight-year global effort to define and implement technologies needed for hydrogen-based energy systems. A critical part of this effort is the development of a hydrogen-fueled gas turbine system to efficiently convert the chemical energy stored in hydrogen to electricity when hydrogen is combusted with pure oxygen. A steam cycle with reheat and recuperation was selected for the general reference system. Variations of this cycle have been examined to identify a reference system having maximum development feasibility while meeting the requirement of a minimum of 70.9 percent thermal efficiency. The strategy applied was to assess both a near-term and a long-term reference plant. The near-term plant requires moderate development based on extrapolation of current steam and gas turbine technology. In contrast, the long-term plant requires more extensive development for an additional high-pressure reheat turbine, has closed-loop steam cooling and extractive feedwater heating, and is more complex than the near-term plant.


In addition to power generation and aircraft propulsion, gas turbine technology has been used for mechanical drive systems, gas and oil transmission pipelines, and naval propulsion. In natural gas pipelines, gas turbines provide mechanical pumping power, using the fluid being pumped as fuel. For marine applications, aero-derivative engines have been developed, yet a major disadvantage is its poor specific fuel consumption at part-load operation. For example, a naval vessel having a maximum speed of thirty knots and a cruise speed of fifteen knots loses considerable efficiency at cruising speed, since the cruise power will be only one-eighth of the maximum power (the power required being proportional to the cube of the speed). One alternative to reduce this concern is the use of a recuperator to heat the air going to the combustor with the heat from the gas turbine's exhaust. Another alternative to overcome high specific fuel consumption at part-load operation is to develop a shipboard combined cycle power plant consisting of gas turbines in conjunction with a steam turbine.

Gas turbines also have been considered for rail and road transportation. The Union Pacific successfully operated large freight trains from 1955 to 1975, several high-speed passenger trains and locomotives were built using aviation-type gas turbines. These, however, gave way to more economical diesels.

The first gas-turbine-propelled car (at 150 kW) was produced in the United Kingdom in 1950. For more than fifty years, significant efforts have been expended on automotive programs; however, diesel and gasoline engines continue to dominate. The major problem is still the poor part-load thermal efficiency of the gas turbine despite the use of a recuperated cycle with variable area nozzle guide vanes. Other problems include lack of sufficient high-temperature material development, and the relatively long acceleration time from idle to full load. For long-haul trucks, gas turbines were developed in the range of 200 to 300 kW. All used a low-pressure cycle ratio with a centrifugal compressor, turbine, and rotary heat exchanger.

A recent convergence of economic opportunities and technical issues has resulted in the emergence of a new class of gas turbine engines called microturbines. Designed for use in a recuperative cycle and pressure ratios of three to one to five to one, they can produce power in the range of 30 to 300 Kw. Initial work on this concept, which is primarily packaged today for cogeneration power generation, started in the late 1970s. In cogeneration applications that can effectively use the waste heat, overall system efficiencies can be greater than 80 percent. Manufacturers are exploring how microturbines can be integrated with fuel cells to create hybrid systems that could raise overall system efficiencies. Many issues, however, are still to be resolved with this approach, including cost and integration.

Another application of gas turbines is in a compressed air energy storage (CAES) system that allows excess base load power to be used as peaking power. It is similar to hydro-pumped storage, and the idea is to store energy during low demand periods by converting electrical power to potential energy. Rather than pumping water up a hill, CAES compresses and stores air in large underground caverns. When the power is needed, the air is allowed to expand through a series of heaters and turbines, and the released energy is then converted back to electricity. To increase output and efficiency, fuel is mixed with the air as it is released, the mixture is burned, and the energy released by combustion is available for conversion to electricity and heat recovery. This is similar to the operation of a standard gas turbine, except with CAES the compressor and turbines are separate machines that each run when most advantageous.


The electricity industry is in the midst of a transition from a vertically integrated and regulated monopoly to an entity in a competitive market where retail customers choose the suppliers of their electricity. The change started in 1978, when the Public Utility Regulatory Act (PURPA) made it possible for nonutility power generators to enter the wholesale market.

From various U.S. DOE sources, projections have been made that the worldwide annual energy consumption in 2020 could be 75 percent higher than it was in 1995. The combined use of fossil fuels is projected to grow faster from 1995 to 2020 than it did from 1970 to 1995. Natural gas is expected to account for 30 percent of world electricity by 2020, compared to 16 percent in 1996.

The power generation cycle of choice today and tomorrow is the combined cycle that is fueled with natural gas. Power generating technologies, regardless of the energy source, must maximize efficiency and address environmental concerns. To support the fuel mix and minimize environmental concerns, advanced coal combustion, fuel cells, biomass, compressed air energy storage, advanced turbine systems, and other technologies such as the development of a hydrogen-fueled cycle are under development.

Beyond the ATS program, the DOE is looking at several new initiatives to work on with industry. One, Vision 21, aims to virtually eliminate environmental concerns associated with coal and fossil systems while achieving 60 percent efficiency for coal-based plants, 75 percent efficiency for gas-based plants, and 85 percent for coproduction facilities. Two additional fossil cycles have been proposed that can achieve 60 percent efficiency. One incorporates a gasifier and solid oxide fuel into a combined cycle; the other adds a pyrolyzer with a pressurized fluidized bed combustor. Also under consideration is the development of a flexible midsize gas turbine. This initiative would reduce the gap between the utility-size turbines and industrial turbines that occurred during the DOE ATS program.

Ronald L. Bannister

See also: Cogeneration; Cogeneration Technologies; Locomotive Technology; Parsons, Charles Algernon; Storage; Storage Technology; Turbines, Steam; Turbines, Wind.


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