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Chapter 3: Capture of CO2 133 Figure 3.15 North Dakota coal gasification plant with 3.3 MtCO2 yr−1 capture using a cold methanol, physical solvent process (cluster of 4 tall columns in the middle of the picture represent the H2S and CO2 capture processes; part of the captured stream is used for EOR with CO2 storage in Weyburn, Saskatchewan, Canada). entrained-flow gasifiers with water slurry feed and direct water quench followed by ‘sour’ (sulphur-tolerant) shift reactors and finally co-removal of CO2 and H2S by physical absorption. With sour shifting, hot raw syngas leaving the gasifier requires only one cooling cycle and less processing. Oxygen requirements increase for slurry fed gasifiers and conversion efficiencies decline with higher cycle efficiency losses with quench cooling. Similar trends are also noted with a shift from bituminous to lower rank sub-bituminous coal and lignite (Breton and Amick, 2002). Some analyses (e.g., Stobbs and Clark, 2005) suggest that the advantages of pre-combustion over post-combustion de-carbonization may be small or disappear for low-rank coals converted with entrained-flow gasifiers. High-pressure, fluidized-bed gasifiers may be better suited for use with low- rank coals, biomass and various carbonaceous wastes. Although there are examples of successful demonstration of such gasifiers (e.g., the high temperature Winkler, Renzenbrink et al., 1998), there has been little commercial-scale operating experience. Since the technology was initially demonstrated in the 1980s, about 4 GWe of IGCC power plants have been built. Most of this capacity is fuelled with oil or petcoke; less than 1 GWe of the total is designed for coal (IEA CCC, 2005) and 3 out of 4 plants currently operating on coal and/or petcoke. This experience has demonstrated IGCC load-following capability, although the technology will probably be used mainly in base load applications. All coal-based IGCC projects have been subsidized, whereas only the Italian oil-based IGCC projects have been subsidized. Other polygeneration projects in Canada, the Netherlands and the United States, as well as an oil-based IGCC in Japan, have not been subsidized (Simbeck, 2001a). The H2S in syngas must be removed to levels of tens of ppm for IGCC plants for compliance with SO2 emissions regulations and to levels much less than 1 ppm for plants that make chemicals or synthetic fuels, so as to protect synthesis catalysts. If the CO2 must be provided for storage in relatively pure form, the common practice would be to recover first H2S (which is absorbed more readily than CO2) from syngas (along with a small amount of CO2) in one recovery unit, followed by reduction of H2S to elemental sulphur in a Claus plant and tail gas clean-up, and subsequent recovery of most of the remaining CO2 in a separate downstream unit. An alternative option is to recover sulphur in the form of sulphuric acid (McDaniel and Hormick, 2002). If H2S/CO2 co-storage is allowed, however, it would often be desirable to recover H2S and CO2 in the same physical absorption unit, which would lead to moderate system cost savings (IEA GHG, 2003; Larson and Ren, 2003; Kreutz et al., 2005) especially in light of the typically poor prospects IGCC has not yet been deployed more widely because of strong competition from the natural gas combined cycle (NGCC) wherever natural gas is readily available at low prices, because coal-based IGCC plants are not less costly than pulverized coal fired steam-electric plants and because of availability (reliability) concerns. IGCC availability has improved in recent years in commercial-scale demonstration units (Wabash River Energy, 2000; McDaniel and Hornick, 2002). Also, availability has been better for industrial polygeneration and IGCC projects at oil refineries and chemical plants where personnel are experienced with the chemical processes involved. The recent rise in natural gas prices in the USA has also increased interest in IGCC. for selling byproduct sulphur or sulphuric acid. Although co- storage of H2S and CO2 is routinely pursued in Western Canada as an acid gas management strategy for sour natural gas projects (Bachu and Gunter, 2005), it is not yet clear that co-storage would be routinely viable at large scales - a typical gasification- based energy project would involve an annual CO2 storage rate of 1-4 Mtonnes yr-1, whereas the total CO2 storage rate for all 48 Canadian projects is presently only 0.48 Mtonnes yr-1 (Bachu and Gunter, 2005). In a coal IGCC, syngas exiting the gasifier is cleaned of particles, H2S and other contaminants and then burned to make electricity via a gas turbine/steam turbine combined cycle. The syngas is generated and converted to electricity at the same site, both to avoid the high cost of pipeline transport of syngas (with a heating value only about 1/3 of that for natural gas) and to cost-effectively exploit opportunities for making extra power in the combined cycle’s steam turbine using steam from syngas cooling. The main drivers for IGCC development were originally the prospects of exploiting continuing advances in gas turbine technology, the ease of realizing low levels of air-pollutant emissions when contaminants are removed from syngas, and greatly reduced process stream volumes compared to flue gas streams from combustion which are at low pressure and diluted with nitrogen from air. 3.5.2.6 Integrated gasification combined cycle (IGCC) for power generation Because of the advantages for gasification of CO2 capture at high partial pressures discussed above, IGCC may be attractive for coal power plants in a carbon-constrained world (Karg and Hannemann, 2004). 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