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Chapter 3: Capture of CO2 recovery becomes essential. For NOx it is the NO2 which leads to the formation of heat stable salts. Fortunately, the level of NO2 is mostly less than 10% of the overall NOx content in a flue gas (Chapel et al., 1999). The allowable SOx content in the flue gas is primarily determined by the cost of the solvent - as this is consumed by reaction with SOx. SO2 concentrations in the flue gas are typically around 300-5000 ppm. Commercially available SO2-removal plants will remove up to 98-99%. Amines are relatively cheap chemicals, but even cheap solvents like MEA (with a price around 1.25 US$ kg-1 (Rao and Rubin, 2002) may require SOx concentrations of around 10 ppm, to keep solvent consumption (around 1.6 kg of MEA/tCO2 separated) and make up costs at reasonable values, which often means that additional flue gas desulphurization is needed. The optimal SO2 content, before the CO2 absorption process is a cost trade-off between CO2-solvent consumption and SO2-removal costs. For the Kerr-Mcgee/ABB Lummus Crest Technology, SO2-removal is typically not justified for SO2 levels below 50 ppm (Barchas and Davis, 1992). For the Fluor Daniel Econamine FG process a maximum of 10 ppm SO2 content is generally set as the feed gas specification (Sander and Mariz, 1992). This can be met by using alkaline salt solutions in a spray scrubber (Chapel et al., 1999). A SO2 scrubber might also double as a direct contact cooler to cool down the flue gas. Careful attention must also be paid to fly ash and soot present in the flue gas, as they might plug the absorber if contaminants levels are too high. Often the requirements of other flue gas treatment are such that precautions have already been taken. In the case of CO2 recovery from a coal-fired boiler flue gas, the plant typically has to be equipped with a DeNOx unit, an electrostatic precipitator or a bag house filter and a DeSOx or flue gas desulphurization unit as part of the environmental protection of the power plant facilities. In some cases, these environmental protection facilities are not enough to carry out deep SOx removal up to the 1-2 ppm level sometimes needed to minimize solvent consumption and its reclamation from sticking of solvent wastes on reclaimer tube surfaces. A key feature of post-combustion CO2 capture processes based on absorption is the high energy requirement and the resulting efficiency penalty on power cycles. This is primarily due to the heat necessary to regenerate the solvent, steam use for stripping and to a lesser extent the electricity required for liquid pumping, the flue gas fan and finally compression of the CO2 product. Later in this chapter, Sections 3.6 and 3.7 present summaries of CO2 capture energy requirements for a variety of power systems and discuss the environmental and economic implications of these energy demands. 117 3.3.2.3 Power generation efficiency penalty in CO2 capture The reduction of the energy penalty is, nevertheless, closely linked to the chosen solvent system. The IEA Greenhouse Programme (IEA GHG) has carried out performance assessments of power plants with post-combustion capture of CO2, taking into consideration the most recent improvements in post- combustion CO2 capture processes identified by technology licensors (IEA GHG, 2004). In this study, Mitsui Babcock Energy Ltd. and Alstom provided information on the use of a high efficiency, ultra-supercritical steam cycle (29 MPa, 600°C, 620°C reheat) boiler and steam turbine for a coal-fired power plant, while for the NGCC case, a combined cycle using a GE 9FA gas turbine was adopted. Fluor provided information on the Fluor Econamine + process based on MEA, and MHI provided information on KEPCO/MHI process based on the KS-1 solvent for CO2 capture. CO2 leaving these systems were compressed to a pressure of 11 MPa. The overall net power plant efficiencies with and without CO2 capture are shown in Figure 3.6, while Figure 3.7 shows the efficiency penalty for CO2 capture. Overall, results from this study show that the efficiency penalty for post-combustion capture in coal and gas fired plant is lower for KEPCO/MHI’s CO2 absorption process. For the purpose of comparison, the performance of power plants with pre-combustion and oxy-fuel capture, based on the same standard set of plant design criteria are also shown in Figures 3.6 and 3.7. In principle, the thermal energy for the regeneration process can be supplied by an auxiliary boiler in a retrofit situation. Most studies, however, focus on an overall process in which the absorption process is integrated into the power plant. The heat requirement is at such levels that low-pressure steam, for example condensing at 0.3 MPa(g), can be used in the reboiler. The steam required for the regeneration process is then extracted from the steam cycle in the power plant. For a coal- fired power station, low-pressure steam will be extracted prior to the last expansion stage of the steam turbine. For a natural gas fired combined cycle, low-pressure steam will be extracted from the last stage in the heat recovery steam generator. Some of this heat can be recovered by preheating the boiler feed water (Hendriks, 1994). Values for the heat requirement for the leading absorption technologies are between 2.7 and 3.3 GJ/ tCO2, depending on the solvent process. Typical values for the electricity requirement are between 0.06 and 0.11 GJ/tCO2 for post-combustion capture in coal- fired power plants and 0.21 and 0.33 GJ/tCO2 for post-combustion capture in natural gas fired combined cycles. Compression of the CO2 to 110 bar will require around 0.4 GJ/tCO2 (IEA GHG, 2004). Integration of the absorption process with an existing power plant will require modifications of the low-pressure part of the steam cycle, as a sizeable fraction of the steam will be extracted and hence will not be available to produce power (Nsakala et al., 2001, Mimura et al.,1995, Mimura et al., 1997). To limit the required modifications, small back-pressure steam turbines using medium pressure steam to drive the flue gas fan and boiler feed water pumps can be used. The steam is then condensed in the reboiler (Mimura et al., 1999). Furthermore, in power plants based on steam cycles more than 50% thermal energy in the steam cycle is disposed off in the steam condenser. If the steam cycle system and CO2 recovery can be integrated, part of the waste heat disposed by the steam condenser can be utilized for regeneration of the chemical solvent.PDF Image | CARBON DIOXIDE CAPTURE AND STORAGE
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