Post-Combustion CO₂ Capture from an Industrial Power Plant Using Five Chemical Solvents: A Comparative TEA

Abstract

CO2 capture processes using five chemical solvents were modeled in Aspen Plus V.12.1 for the capture of more than 90% CO2 from a 456 ton/hour split flue gas stream containing 12.02 mol% CO2 emitted by the Longview 780 MW power plant (West Virginia, USA). Since the flue gas contained 33.10 ppmv SO2 and 35.47 ppmv NO2, a gas polishing process, using deionized water (DIW), was included in the model for complete scrubbing of SO2 and NO2 from the raw flue gas before the CO2 capture process. The five chemicals used for CO2 capture included three amine-based solvents (ABs) (monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), and (piperazine/methyldiethanolamine (PZ/MDEA)), and two amino acid-based solvents (AAs) (sodium glycinates (SGS) and potassium glycinates (PGS)). Since SGS and PGS exhibit phase separation, the CO2 capture processes followed two distinct pathways: Pathway (i) involved direct CO2 capture using all five solvents, and Pathway (ii) focused on bicarbonate nanomaterials production using only SGS and PGS. A Techno-economic assessment (TEA) of the CO2 capture processes was conducted and the corresponding process hydraulics and mass transfer characteristics were calculated. The simulation results revealed the following: (1) for Pathway (i), the levelized costs of CO2 capture (LCOC) for PGS were lower than those of SGS, MEA, AMP, and PZ/MDEA; (2) for Pathway (ii), the LCOC values of PGS were lower than those of SGS; (3) Pathway (ii) was more economically favorable than Pathway (i); and (4) under the operating conditions used, the two-phase pressure drop values were negligible, and the liquid-side mass transfer coefficients (kL) were an order of magnitude smaller than gas-side mass transfer coefficients (kG), suggesting that the gas-liquid mass transfer resistance (1/kL) was in the liquid-side.