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About IGCC Power

Integrated Gasification Combined Cycle (IGCC).

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How is gasification used to generate electricity?
How does an IGCC powerplant work?
What is the present state-of-the-art IGCC design?
Where are coal-based IGCC projects operating currently?
How does IGCC compare to other clean coal technologies?
Economic Comparison
Environmental Comparison

How is gasification used to generate electricity?

Coal and other hydrocarbons have been gasified for the production of chemicals, fertilizers, and synthetic fuels for more than half a century. However, it is only in the last 20 years that gasification has been used for the production of electricity using the Integrated Gasification Combined Cycle (IGCC) process. As illustrated below, this nomenclature means that the design is based upon: (1) an integrated; (2) gasification “island”; and (3) a combined cycle “power block.”

How does an IGCC powerplant work?

A hydrocarbon feedstock is gasified in a high-pressure, high-temperature gasifier with either oxygen or air produced in an air separation unit (ASU).

The resulting synthesis gas (syngas) is cooled, cleaned, and fired in a gas turbine.

The hot exhaust from the gas turbine passes through a heat recovery steam generator (HRSG) where it produces steam that drives a steam turbine.

Electric power is produced from both the gas and steam turbine-generators.

By removing the emission-forming constituents from the syngas under pressure before combustion in the power block, an IGCC powerplant produces very low levels of criteria air pollutants (NOx, SO2, and PM) and volatile mercury.

What is the present state-of-the-art IGCC design?

There are many variations to the basic IGCC design (especially when it comes to “integration” between the gasifier island, ASU, and power block). Nonetheless, the following observations can be made:

It is the general consensus among IGCC plant designers that the preferred design today is one in which the ASU derives 25 to 50 percent of its oxygen supply from the gas turbine compressor and the rest from a separate air compressor.

Pressurized gasification is generally preferred to avoid large auxiliary power losses for compression of the syngas. (High-pressure oxygen-blown gasification also provides advantages if/when CO2 capture is mandated at a later date.)

Entrained-flow gasifiers that operate in the higher-temperature slagging regions have been selected for the majority of IGCC project applications. A major advantage of using high-temperature entrained-flow gasifiers in an IGCC project is that they avoid tar formation and its related problems. The high reaction rate also allows single gasifiers to be built with large gas outputs sufficient to fuel the large commercial gas turbines now entering the marketplace.


Most of the large components of an IGCC plant (such as the cryogenic cold box for the ASU, the gasifier, the syngas coolers, the gas turbine, and the HRSG sections) can be shop-fabricated and transported to the site. Construction and installation time is estimated to be about three years, the same as for a comparably sized pulverized coal plant.

Where are coal-based IGCC projects operating currently?

The basic IGCC concept was first successfully demonstrated at commercial scale at the pioneer Cool Water Project in Southern California from 1984 to 1989. There are currently two commercial-size, coal-based IGCC plants in the United States and two in Europe. The two U.S. projects were supported initially under the DOE’s Clean Coal Technology demonstration program, but are now operating commercially without DOE support.

The 262 MWe Wabash River IGCC repowering project in Indiana started up in October 1995 and uses the E-Gas gasification technology (which was acquired by ConocoPhillips in 2003). The 250 MWe Tampa Electric Co. Polk Power Station IGCC project in Florida started up in September 1996 and is based on Texaco gasification technology (acquired by GE Energy in 2004).

The first of the European IGCC plants was the NUON (formerly SEP/Demkolec) project in Buggenum, the Netherlands, using Shell gasification technology. It began operation in early 1994. The second European project, the ELCOGAS project in Puertollano, Spain, uses the Prenflo (Krupp-Uhde) gasification technology and started coal-based operations in early 1998. In 2002, Shell and Krupp-Uhde announced that henceforth their technologies would be merged and marketed as the Shell gasification technology.

How does IGCC compare to other clean coal technologies?

There are two kinds of electric powerplants: those designed for “baseload” (24-7) operations and those designed to meet demand just at “peak” times.

Coal powerplants typically provide baseload capacity.
Natural gas combined cycle plants generally provide peak capacity.
IGCC powerplants are being designed primarily for the baseload power market.

Because IGCC will compete most directly against other clean coal technologies – especially the supercritical pulverized coal (SCPC) design – it is useful to compare these two technologies with respect to: (1) capital costs and cost of energy produced; (2) environmental impacts; and (3) potential for cost-effective carbon dioxide capture. It is also useful to consider natural gas combined cycle as an additional benchmark as well.

Economic Comparison

Capital Costs. According to information developed by GE Energy and Bechtel as part of their “Reference Plant Offering,” the total installed cost of a new state-of-the-art SCPC powerplant varies with plant size and with the degree of reuse of existing site infrastructure. In a paper presented at the 2005 Gasification Technologies Conference, they stated that:

At a nominal plant size of 600 MWe, the price for a SCPC plant in the Ohio River Valley would typically fall within the 1,200 to 1,460 $/kW range.
Presently, IGCC plants cost 20 to 25 percent more than a comparable SCPC powerplant at any given site. However, the GE Energy-Bechtel alliance’s next generation IGCC plants are targeted to enter the marketplace with a price that will reduce that capital cost premium to the range of 10 percent.

Cost of Electricity. Another key measure of importance to decision-makers trying to choose between different coal-power options is the so-called “cost of electricity.” The environmental benefits of IGCC partially close the cost-of-electricity gap caused by the 20 to 25 percent capital cost premium. As illustrated below, assuming a 10 percent capital cost premium and the inherent improved environmental performance of IGCC plants vs. SCPC plants, results are near parity for the cost of electricity for next generation IGCC and SCPC projects.

Environment Comparison

Criteria Air Pollutants. Air pollutants emitted from vehicles and stationary sources such as powerplants are regulated in the United States and other nations. These so-called criteria air pollutants include sulfur dioxide (SO2), nitrogen oxides (NOx), particulate matter (PM), and carbon monoxide (CO). The U.S. Environmental Protection Agency (EPA) has established New Source Performance Standards for large-scale, combustion-based powerplants that use coal. As illustrated below, present and next-generation IGCC facilities: (1) meet or exceed the EPA’s standards; (2) emit fewer criteria air pollutants than SCPC plants; and (3) compare favorably with natural gas combined cycle (NGCC) facilities.


Mercury. There has been a long-running debate in the United States about the regulation of mercury from powerplants. This debate climaxed (for now) on March 15, 2005, when the EPA issued a final Clean Air Mercury rule that instituted a two-phase reduction in mercury emissions. The first phase (due by 2010) will see mercury emissions reduced through co-benefit reductions which will occur as SO2 and NOx emissions are limited at older plants. The second phase (due by 2018) will see mercury emissions limited further through a national limit (15 tons per year), pro rata limits, and a “cap and trade” system.

The December 2002 DOE study entitled, Major Environmental Aspects of Gasification-Based Power Generation Technologies, reached the following conclusions concerning mercury in IGCC and other clean-coal power systems:

Compared with combustion-based power plants, IGCC plants have a major advantage when it comes to mercury control. Commercial methods have been employed for many years that remove trace amounts of mercury from natural gas and gasifier syngas. Both molecular sieve technology and activated carbon beds have been used for this purpose, with 90 to 95 percent removal efficiency reported… A recent DOE cost study was conducted for applying a packed-bed carbon adsorption system to an IGCC plant. Based on an 18-month carbon replacement cycle and 90 percent reduction of mercury emissions, the total cost of mercury reduction is estimated to be $3,412 per pound of mercury removed, which is projected to be about one-tenth the cost of flue gas-based [SCPC] mercury control.


Solid Wastes. In terms of volumes of waste material produced, as well as the potential for leaching of toxic substances into soil and groundwater, IGCC has demonstrated reduced environmental impact compared with similarly sized coal combustion-based powerplants. The largest solid waste stream produced in an IGCC facility is slag (or bottom ash in some designs). Slag is a black, glassy, sand-like material that can be a marketable byproduct and leachability data obtained from different gasifiers unequivocally shows that gasifier slag is highly “non-leachable.”


Carbon Dioxide. Since coal plants have a long lifetime, decisions made by utility executives and regulators in the next few years will have implications for decades to come. Of particular concern to many people is the large volume of carbon dioxide (CO2) emitted by coal-based powerplants. This concern arises from the fact that CO2 is one of the so-called “greenhouse gases” (which trap heat in the atmosphere) and many scientists believe that increased greenhouse gas emissions will soon lead to global climate change.

If electrical energy decision-makers turn return to coal – as now seems inevitable – the most “climate-friendly” coal technology is gasification. While it is theoretically possible to capture CO2 from conventional coal-fired plants, to do so will be prohibitively expensive, with CO2 capture and sequestration (storage) projected to increase the cost of electricity from such plants by __ to __ percent. Of course, the cost of CO2 capture and sequestration in an IGCC plant is also projected to be expensive, but it only adds __ to __ percent to the cost of electricity. The principal reason for this cost differential is that the CO2 in an IGCC plant is separated from the syngas before combustion, but the CO2 in a conventional coal plant is removed from the post-combustion exhaust gases.

It should also be noted that all of the technologies necessary for CO2 capture and compression at an IGCC plant, as well as for transport and injection of CO2 into geologic or oceanic formations, are in commercial use today. The big technical uncertainty at present is whether CO2 can be permanently sequestered in such formations. Although preliminary tests are encouraging, additional long-term studies are still required before final conclusions can be drawn.


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  © 2004-2009 Fred H. Hutchison

Edited on: March 27, 2009