A combined cycle is characteristic of a power producing engine or plant that employs more than one thermodynamic cycle. Heat engines are only able to use a portion of the energy their fuel generates (usually less than 50%). The remaining heat from combustion is generally wasted. Combining two or more "cycles" such as the Brayton cycle and Rankine cycle results in improved overall efficiency.
In a combined cycle power plant (CCPP), or combined cycle gas turbine (CCGT) plant, a gas turbine generator generates electricity and the waste heat is used to make steam to generate additional electricity via a steam turbine; this last step enhances the efficiency of electricity generation. Most new gas power plants in North America and Europe are of this type. In a thermal power plant, high-temperature heat as input to the power plant, usually from burning of fuel, is converted to electricity as one of the outputs and low-temperature heat as another output. As a rule, in order to achieve high efficiency, the temperature difference between the input and output heat levels should be as high as possible (see Carnot efficiency). This is achieved by combining the Rankine (steam) and Brayton (gas) thermodynamic cycles. Such an arrangement used for marine propulsion is called COmbined Gas (turbine) And Steam (turbine) (COGAS).
Design principle
In a steam power plant water is the working medium. High pressure steam requires strong, bulky components. High temperatures require expensive alloys made from nickel or cobalt, rather than inexpensive steel. These alloys limit practical steam temperatures to 655 °C while the lower temperature of a steam plant is fixed by the boiling point of water. With these limits, a steam plant has a fixed upper efficiency of 35 to 40%.
For gas turbines these limitations do not apply. Gas cycle firing temperatures above 1,200 °C are practicable. So, a combined cycle plant has a thermodynamic cycle that operates between the gas-turbine's high firing temperature and the waste heat temperature near the boiling point of water.
A gas turbine has a compressor, burner and turbine. The input temperature to the turbine is relatively high (900 to 1,350 °C) but the output temperature of the flue gas is also high (450 to 650 °C).
The temperature of a gas turbine's flue gas is therefore high enough to make steam for a second steam cycle (a Rankine cycle), with a live steam temperature between 420 and 580 °C. The condenser is usually cooled by water from a lake, river, sea or cooling towers.
The output heat of the gas turbine's flue gas is utilized to generate steam by passing it through a heat recovery steam generator (HRSG).
By combining both processes, high input temperatures and low output temperatures can be achieved. The efficiency of the cycles add, because they are powered by the same fuel source.
Efficiency of CCGT plants
The thermal efficiency of a combined cycle power plant is the net power output of the plant divided by the heating value of the fuel. If the plant produces only electricity, efficiencies of up to 59% can be achieved. In the case of combined heat and power generation, the efficiency can increase to 85%.
Supplementary firing
The HRSG can be designed with supplementary firing of fuel after the gas turbine in order to increase the quantity or temperature of the steam generated. Without supplementary firing, the efficiency of the combined cycle power plant is higher, but supplementary firing lets the plant respond to fluctuations of electrical load. Supplementary burners are also called duct burners.
More fuel is sometimes added to the turbine's exhaust. This is possible because the turbine exhaust gas (flue gas) still contains some oxygen. Temperature limits at the gas turbine inlet force the turbine to use excess air, above the optimal stoichiometric ratio to burn the fuel. Often in gas turbine designs part of the compressed air flow bypasses the burner and is used to cool the turbine blades.
Fuel for combined cycle power plants
Combined cycle plants are usually powered by natural gas, although fuel oil, synthetic gas or other fuels can be used. The supplementary fuel may be natural gas, fuel oil, or coal.
Integrated Gasification Combined Cycle (IGCC)
An Integrated Gasification Combined Cycle, or IGCC, is a power plant using synthetic gas (syngas). Below is a schematic flow diagram of an IGCC plant:
The gasification process can produce syngas from high-sulfur coal, heavy petroleum residues and biomass.
The plant is called "integrated" because its syngas is produced in a gasification unit in the plant which has been optimized for the plant's combined cycle. The gasification process produces heat, and this is reclaimed by steam "waste heat boilers". The steam is utilized in steam turbines.
There are currently (2007) only two IGCC plants generating power in the U.S.; however, several new IGCC plants are expected to come online in the U.S. in the 2012-2020 time frame.
The first generation of IGCC plants polluted less than contemporary coal-based technology, but also polluted water: For example, the Wabash River Plant "routinely" violated its water permit because it emitted arsenic, selenium and cyanide. The Wabash River Generating Station has now wholly owned and operated by the Wabash River Power Association, and currently operates as one of the cleanest solid fuel power plants in the world.
New IGCC plants based on these demonstration projects can achieve low NOx emissions, greater than 90-95% mercury removal, and greater than 99% sulfur dioxide (SO2) removal.
IGCC is now touted as "capture ready" and could capture and store carbon dioxide. IGCC's can be outfitted for carbon capture much more easily and cheaply than conventional and supercritical pulverized coal plants because the carbon can be removed in the gasifier, before the fuel is combusted. Even without carbon capture, the high thermal efficiency of IGCC plants means that IGCC plants release less carbon while producing the same amount of energy.
The main problem for IGCC is its extremely high capital cost, upwards of $3,593/kW[1]. Official US government figures give more optimistic estimates [2] of $1491/kw installed capacity (2005 dollars) v $1290 for a conventional clean coal facility.This is about 20% greater cost than a conventional pulverized coal plant, but the U.S. Department of Energy and many states offer subsidies for clean coal technology projects that could help to bridge the cost gap.
However, the per megawatt-hour cost of an IGCC plant vs. a pulverized coal plant coming online in 2010 would be $56 vs $52. And IGCC becomes even more attractive when you include the costs of carbon capture and sequestration, IGCC becoming $79 per megawatt-hour vs. $95 per megawatt-hour for pulverized coal. [3]
The DOE Clean Coal Demonstration Project helped construct 3 IGCC plants: Wabash River in Indiana, Polk in Tampa, Florida (online 1996), and Pinon Pine in Reno, Nevada. In the Reno demonstration project, researchers found that then-current IGCC technology would not work more than 300 feet (100m) above sea level[4]. The plant failed. [5]
The power generation industry has yet to show that IGCC is reliable. Of five demonstration facilities, none had availabilities comparable to conventional CCGTs or coal-fired power plants. Wabash River was down repeatedly for long stretches due to gasifier problems, and the gasifier problems have not been remedied -- subsequent projects, such as Excelsior's Mesaba Project, have a third gasifier and train built in. However, the past year has seen Wabash River running reliably, with availability comparable to or better than other technologies.
General Electric is currently designing an IGCC model plant that should introduce greater reliability. GE's model features advanced turbines optimized for the coal syn-gas. Eastman's industrial gasification plant in Kingsport, TN uses a GE Energy solid-fed gasifier. Eastman, a fortune 500 company, built the facility in 1983 without any state or federal subsidies and turns a profit. [6][7]
There are several refinery-based IGCC plants in Europe that have demonstrated good availability (90-95%) after initial shakedown periods. Several factors help this performance:
First, none of these facilities use advanced technology ("F" type) gas turbines.
Second, all refinery-based plants use refinery residues, rather than coal, as the feedstock. This eliminates coal handling and coal preparation equipment and its problems. Also, there is a much lower level of ash produced in the gasifier, which reduces cleanup and downtime in its gas cooling and cleaning stages.
Third, these non-utility plants have recognized the need to treat the gasification system as an up-front chemical processing plant, and have reorganized their operating staff accordingly.
Another IGCC success story has been the 250 MW Buggenum plant in The Netherlands. It also has good availability. This coal-based IGCC plant currently uses about 30% biomass as a supplemental feedstock. The owner, NUON, is paid an incentive fee by the government to use the biomass. NUON has begun site preparation for a much larger plant - about 1200 MW. Although not confirmed, it is expected that they will specify "F" class advanced gas turbines.
A new generation of IGCC-based coal-fired power plants has been proposed, although none is yet under construction. Projects are being developed by AEP, Duke Energy, and Southern Company in the US, and in Europe, by E.ON and Centrica (both UK), RWE (Germany) and NUON (Netherlands). In Minnesota, the state's Dept. of Commerce analysis found IGCC to have the highest cost, with an emissions profile not significantly better than pulverized coal. In Delaware, the Delmarva and state consultant analysis had essentially the same results.
The high cost of IGCC is the biggest obstacle to its integration in the power market; however, most energy executives recognize that carbon regulation is coming soon. Bills requiring carbon reduction are being proposed again both the House and the Senate, and with the Democratic majority it seems likely that with the next President there will be a greater push for carbon regulation. The Supreme Court decision requiring the EPA to regulate carbon (Commonwealth of Massachusetts et al. v. Environmental Protection Agency et al.)[8] also speaks to the likelihood of future carbon regulations coming sooner, rather than later. With carbon capture, the cost of electricity from an IGCC plant would increase approximately 30%. For a natural gas CC, the increase is approximately 33%. For a pulverized coal plant, the increase is approximately 68%. This potential for less expensive carbon capture makes IGCC an attractive choice for keeping low cost coal an available fuel source in a carbon constrained world.
Automotive use
Combined cycles have traditionally only been used in large power plants. BMW, however, has proposed that automobiles use exhaust heat to drive steam turbines.[9] It may be possible to use the pistons in a reciprocating engine for both combustion and steam expansion.[10]
Aeromotive use
Some versions of the Wright R-3350 were produced as "Turbo-compound" engines. Three turbines driven by exhaust gases, known as "Power recovery turbines", provided nearly 600 hp at takeoff. These turbines added power to the engine crankshaft through bevel gears and fluid couplings.
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