In an IGCC system coal is not burned but rather partially oxidized (reacted with limited quantities of oxygen from an air separation plant, and with steam) at high pressure in a gasifier. The product of gasification is so-called synthesis gas, or syngas, which is composed mostly of carbon monoxide and hydrogen, undiluted with nitrogen. In current practice, IGCC operations remove most conventional pollutants from the syngas and then burn it to turn both gas and steam turbinegenerators in what is called a combined cycle.
In an IGCC plant designed to capture CO2, the syngas exiting the gasifier, after being cooled and cleaned of particles, would be reacted with steam to produce a gaseous mixture made up mainly of carbon dioxide and hydrogen. The CO2 would then be extracted, dried, compressed and transported to a storage site. The remaining hydrogen-rich gas would be burned in a combined cycle plant to generate power.
Analyses indicate that carbon dioxide capture at IGCC plants consuming high-quality bituminous coals would entail significantly smaller energy and cost penalties and lower total generation costs than what could be achieved in conventional coal plants that captured and stored CO2. Gasification systems recover CO2 from a gaseous stream at high concentration and pressure, a feature that makes the process much easier than it would be in conventional steam facilities. (The extent of the benefits is less clear for lower-grade subbituminous coals and lignites, which have received much less study.) Precombustion removal of conventional pollutants, including mercury, makes it feasible to realize very low levels of emissions at much reduced costs and with much smaller energy penalties than with cleanup systems for flue gases in conventional plants.
Captured carbon dioxide can be transported by pipeline up to several hundred kilometers to suitable geologic storage sites and subsequent subterranean storage with the pressure produced during capture. Longer distances may, however, require recompression to compensate for friction losses during pipeline transfer.
Overall, pursuing CCS for coal power facilities requires the consumption of more coal to generate a kilowatt-hour of electricity than when CO2 is vented—about 30 percent extra in the case of coal steam-electric plants and less than 20 percent more for IGCC plants. But overall coal use would not necessarily increase, because the higher price of coal-based electricity resulting from adding CCS equipment would dampen demand for coal-based electricity, making renewable energy sources and energy-efficient products more desirable to consumers.
The cost of CCS will depend on the type of power plant, the distance to the storage site, the properties of the storage reservoir and the availability of opportunities (such as enhanced oil recovery) for selling the captured CO2. A recent study co-authored by one of us (Williams) estimated the incremental electric generation costs of two alternative CCS options for coal IGCC plants under typical production, transport and storage conditions. For CO2 sequestration in a saline formation 100 kilometers from a power plant, the study calculated that the incremental cost of CCS would be 1.9 cents per kilowatt-hour (beyond the generation cost of 4.7 cents per kilowatt-hour for a coal IGCC plant that vents CO2—a 40 percent premium). For CCS pursued in conjunction with enhanced oil recovery at a distance of 100 kilometers from the conversion plant, the analysis finds no increase in net generation cost would occur as long as the oil price is at least $35 per barrel, which is much lower than current prices.
CCS Now or Later?
Many electricity producers in the industrial world recognize that environmental concerns will at some point force them to implement CCS if they are to continue to employ coal. But rather than building plants that actually capture and store carbon dioxide, most plan to construct conventional steam facilities they claim will be “CO2 capture ready”—convertible when CCS is mandated.