Integrating MEA Regeneration with CO2 Compression and Peaking to Reduce CO2 Capture Costs (2005)

Capturing CO{sub 2} from coal-fired power plants is a necessary component of any large-scale effort to reduce anthropogenic CO{sub 2} emissions. Conventional absorption/stripping with monoethanolamine (MEA) or similar solvents is the most likely current process for capturing CO{sub 2} from the flue gas at these facilities. However, one of the largest problems with MEA absorption/stripping is that conventional process configurations have energy requirements that result in large reductions in the net power plant output. Several alternative process configurations for reducing these parasitic energy requirements were investigated in this research with the assistance of the Platte River Power Authority, based on recovering energy from the CO{sub 2} compression train and using that energy in the MEA regeneration step. In addition, the feasibility of selective operation of the amine system at a higher CO{sub 2} removal efficiency during non-peak electricity demand periods was also evaluated. Four process configurations were evaluated: A generic base case MEA system with no compression heat recovery, CO{sub 2} vapor recompression heat recovery, and multipressure stripping with and without vapor recompression heat recovery. These configurations were simulated using a rigorous rate-based model, and the results were used to prepare capital and operating cost estimates. CO{sub 2} capture economics are presented, and the cost of CO{sub 2} capture (cost per tonne avoided) is compared among the base case and the alternative process configurations. Cost savings per tonne of CO{sub 2} avoided ranged from 4.3 to 9.8 percent. Energy savings of the improved configurations (8-10%, freeing up 13 to 17 MW of power for sale to the grid based on 500 MW unit ) clearly outweighed the modest increases in capital cost to implement them; it is therefore likely that one of these improved configurations would be used whenever MEA-based (or similar) scrubbing technologies are implemented. In fact, the payback on capital for the most promising heat integration configurations (Cases 3 and 4) is only six months to one year (based on $0.06/kWh). Another significant result is that the reboiler steam requirement could be reduced by up to 39% with the advanced process configurations. Selective operation of the amine system was found to be economic only if the value of peak electricity was in excess of approximately $230/MWh (from the assumed $130/MWh to buy power from a supplemental natural gas peak turbine) and, therefore, is not considered to be a reasonable option for minimizing CO{sub 2} capture costs. These results indicate an improvement to commercial MEA-based technologies, which helps to incrementally meet DOE's Sequestration Program targets when coupled with other process improvements. For example, DOE's target goal of $20/tonne of CO{sub 2} could potentially be achieved by combining use of the heat integration configurations evaluated in this study and other advanced amine solvents (instead of conventional MEA) that have been developed to further reduce the reboiler duty steam requirements. It is expected that the advanced amines could add another 15% savings in cost of CO{sub 2} captured. In addition, advanced aqueous-based solvent approaches already exist and may be commercialized more quickly than other approaches.