Download (direct link):
In the IGCC plant, coal is gasified at a high pressure (about 50 bar) and temperature (about 1400°C) with oxygen and steam in an entrained flow gasifier (Fig. C-15). In an IGCC plant without CO2 capture, the fuel gas would be cooled and contaminants, such as dust and hydrogen sulfide, would be removed before burning the gas in the gas turbine combustor.
Due to its higher pressure and lower gas flow, it is advantageous to capture CO2 in the fuel gas upstream of the gas turbine instead of from the exhaust gases. The fuel gas contains about 40 vol% CO, 28 vol% H2, 18% H2O, and 10 vol% CO2. Since the CO (carbon monoxide) in the fuel gas would be emitted as CO2 in the gas turbine exhaust gas, it must be converted to CO2 prior to the CO2 removal. This is achieved with steam according to the shift reaction, CO + H2O ^ CO2 + H2. Medium pressure steam is extracted from the steam cycle. The steam demand is 0.5 kg H2O/kg gas. The shift takes place in multiple catalytic reactors with intercooling at about 250-350°C.
After the sift, the CO2 content in the gas has increased to 30 vol%. Because of the high pressure and concentration, a CO2 removal process based on physical absorption, like the Selexol process, is most suitable for this application. The
C-16 Carbon Dioxide (CO2); CO2 Disposal
FIG. C-15 Process scheme for a coal-based IGCC (integrated gasification combined cycle) power plant with shift (conversion of CO to CO2) and CO2 capture upstream of the gas turbine combustion chamber. (Source: Vattenfall Utveckling AB.)
removal efficiency is assumed to be 90 percent. Hydrogen sulfide is selectively removed before the CO2 removal. The sulfur-rich gas is transferred to a Claus unit, where elementary sulfur is produced. Regeneration of the absorbent is achieved by temperature increase and flashing. Low-pressure steam for the regeneration is extracted from the steam cycle. The dry isolated CO2 is pressurized and liquefied.
After CO2 removal, the hydrogen-rich fuel gas is burned in a gas turbine. A hydrogen-rich gas would most likely be a good gas turbine fuel. The gas turbine combustor must, of course, be designed for this type of fuel gas, since hydrogen has somewhat different combustion characteristics than natural gas. Combustion of hydrogen/steam mixtures for utilization in future advanced gas turbine cycles is investigated by Westinghouse. As in an IEA study, a Siemens V94.4 gas turbine has been assumed.
Carbon dioxide neutral coproduction of methanol, power, and district heating
Carbon dioxide neutral production and utilization of methanol as an automotive fuel for the transport sector integrated with production of electric power and district heat could be achieved with biomass combined with natural gas or coal as a raw material. An amount of CO2 corresponding to the carbon in the fossil fuel then has to be captured and disposed into, e.g., an aquifer. Examples of a few such options
Carbon Dioxide (CO2); CO2 Disposal C-17
FIG. C-16 CO2 neutral production of methanol, power and district heat by co-gasification of biomass and coal combined with CO2 capture. (Source: Vattenfall Utveckling AB.)
have been studied based on IEA studies, other literature, and Vattenfall in-house information.
Co-gasification of biomass and coal. Coal and biomass are gasified in an entrained flow gasifier at 1400°C, 40 bar with oxygen and steam (Fig. C-16). Before being gasified, the biomass is dried in a steam drier, lowering its moisture content from about 50 percent to 10 percent, followed by milling. The air separation unit (ASU) is based on cryogenic separation. The syngas generated in the gasifier is cooled and cleaned from dust and sulfur. Heat is extracted to be used in the steam cycle.
The syngas contains about 28 vol% H2 and 39 vol% CO at the inlet of the methanol synthesis reactor. Since both biomass and coal have low hydrogen contents, a novel methanol synthesis process under development by Chem. Systems/Air Products in the U.S., called LPMeOH (Liquid Phase Methanol Synthesis), has been selected. This process is less sensitive to the inlet syngas composition—mainly the ratio of (H2 - CO2)/(CO + CO2)—than the current commercially available methanol synthesis processes. It has been assumed that 20 percent of the carbon input in the fuel is converted to methanol. Assuming only CO reacts according to CO + 2H2 ^ CH3OH, the CO conversion is 25 percent on a molar basis. The methanol synthesis reaction is highly exothermic, and the released heat is utilized in the steam cycle.
The unreacted outlet gas from the methanol synthesis reactor contains mainly CO and H2O. By adding steam, the CO is converted to CO2 according to CO + H2O ^ H2 + CO2 in the shift reactors. Like in an IGCC power plant case, a 95 percent conversion of CO has been assumed. The CO2 content in the gas then increases from