Energy Fuels 2009, 23, 4822–4830 Published on Web 08/11/2009
: DOI:10.1021/ef900281v
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Hydrogen Sulfide and Carbon Dioxide Removal from Dry Fuel Gas Streams Using an Ionic Liquid as a Physical Solvent†,‡ Yannick J. Heintz,§, Laurent Sehabiague, Badie I. Morsi,*,§, Kenneth L. Jones§ David R. Luebke,§ and Henry W. Pennline§ §
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National Energy Technology Laboratory, United States Department of Energy (U.S. DOE), Post Office Box 10940, Pittsburgh, Pennsylvania 15236, and Chemical and Petroleum Engineering Department, University of Pittsburgh, Pittsburgh, Pennsylvania 15261 Received March 31, 2009. Revised Manuscript Received July 13, 2009
The mole fraction solubilities (x*) and volumetric liquid-side mass-transfer coefficients (kLa) for H2S and CO2 in the ionic liquid, TEGO IL K5, (a quaternary ammonium polyether) were measured under different pressures (up to 30 bar) and temperatures (up to 500 K) in a 4 L ZipperClave agitated reactor. CO2 and N2, as single gases, and a H2S/N2 gaseous mixture were used in the experiments. The solubilities of H2S and CO2 were found to increase with pressure and decrease with temperature within the experimental conditions used. The H2S solubilities in the ionic liquid (IL) were greater than those of CO2 within the temperature range investigated (300-500 K) up to a H2S partial pressure of 2.33 bar. Hence, the IL can be effectively used to capture both H2S and CO2 from dry fuel gas stream within the temperature range from 300 to 500 K under a total pressure up to 30 bar. The presence of H2S in the H2S/N2 mixture created mass-transfer resistance, which decreased kLa values for N2. The kLa and x* values of CO2 were found to be greater than those of N2 in the IL, which highlight the stronger selectivity of this physical solvent toward CO2 than toward N2. In addition, within the temperature range from 300 to 500 K, the solubility and kLa of H2S in the IL were greater than those of CO2, suggesting that not only can H2S be more easily captured from dry fuel gas streams but also a shorter absorber can be employed for H2S capture than that for CO2.
strongly depend upon the type of gasifier used.3,4 Furthermore, after a two-stage or three-stage water-gas-shift (WGS) reactor, the shifted fuel gas temperature is expected to be about 508 K.4 Actually, the IGCC is considered as the most promising process for power generation because of its high thermal efficiency and low emissions and its ability to use different feedstocks.5 For the IGCC process to become commercially viable, however, all contaminants in the syngas have to be removed before combustion and the emission control technologies should target the removal of Hg, As, Cd, Se, SOx, NOx, and particulates, in addition to the other contaminants present in high concentration, such as H2S and CO2 (acid gas). Currently, technologies for removal of acid gases from the syngas stream used in the IGCC processes fall into three categories, namely, cold-, warm-, and hot-gas cleanup.5 In cold-gas cleanup, H2S and CO2 are removed from syngas by first concentrating them with either amine-based chemical solvents, such as methyldiethanolamine (MDEA), or refrigerated physical solvents, such as chilled methanol,6 mixture of dimethylethers of polyethylene glycol or n-formylmorpholine/ n-acetylmorpholine.5,7-9 These solvents were reported to be effective in removing nearly all of the undesirable contaminants
1. Introduction Combustion- and gasification-based systems are the two main fossil-fuel technologies currently being developed for carbon-free power generation. In the former, pulverized coal is directly combusted to generate high-pressure steam, which runs a turbine, which in turn runs a power generator with an overall thermal efficiency of about 35%. In the latter, coal and/or biomass mixed with steam and oxygen (or air) is gasified at high-pressure and -temperature to produce syngas, which is sent to an integrated gasification combined cycle (IGCC) process for power generation, with an overall thermal efficiency nearing 40%.1,2 The temperature and pressure of the fuel gas stream produced via gasification technologies †
Progress in Coal-Based Energy and Fuel Production. Disclaimer: References in this report to any specific commercial process, product, or service is to facilitate understanding and does not necessarily imply its endorsement or favoring by the United States Department of Energy. *To whom correspondence should be addressed. E-mail: morsi@pitt. edu. (1) Ratafia-Brown, J. A.; Manfredo, L. M.; Hoffmann, J. W.; Ramezan, M.; Stiegel, G. J. An environmental assessment of IGCC power systems. In Proceedings of the 19th Annual International Pittsburgh Coal Conference, Pittsburgh, PA, Sept 23-27, 2002; pp 235-250. (2) Vidaurri, J.; Larsen, R.; Martin, J.; Looker, M.; Gebhard, S.; Srinivas, G. Multicontaminant warm gas cleanup. In Proceedings of the 24th Annual International Pittsburgh Coal Conference, Johannesburg, South Africa, Sept 10-14, 2007; pp 194/1-194/14. (3) Klara, J. M.; Woods, M. C.; Capicotto, P. J.; Haslbeck, J. L.; Kuehn, N. J.; Matuszewski, M.; Pinkerton, L. L.; Rutkowski, M. D.; Schoff, R. L.; Vaysman, V. Cost and Performance Baseline for Fossil Energy Plants: Bituminous Coal and Natural Gas to Electricity; National Energy Technology Laboratory, U.S. Department of Energy, Research and Development Solutions, LLC (RDS): Pittsburgh, PA, Aug 2007; Revision 1, Vol. 1. ‡
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(4) Stiegel, G. J. Gasification;Versatile Solutions; National Energy Technology Laboratory, U.S. Department of Energy: Pittsburgh, PA, Oct 10, 2007; Version O. (5) Korens, N.; Simbeck, D. R.; Wilhelm, D. J.; Longanbach, J. R.; Stiegel, G. J. Process screening analysis of alternative gas treating and sulfur removal for gasification. Revised Final Report, SFA Pacific, Inc., Mountain View, CA, U.S. Department of Energy, National Energy Technology Laboratory, Pittsburgh, PA, Dec 2002; Task Order 73965600100. (6) Hochgesand, G. Rectisol and purisol. Ind. Eng. Chem. 1970, 62 (7), 37–43.
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Energy Fuels 2009, 23, 4822–4830
: DOI:10.1021/ef900281v
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from syngas. A comparison among chemical and physical solvent-based processes reveals the following: (1) The heat requirements for solvent regeneration in the MDEA chemical process are greater than those needed for the physical solventbased processes. (2) The glycol process is generally more expensive than the MDEA process; however, its package, including total acid gas removal (AGR), sulfur recovery, and tail gas treatment could be more cost-effective than the MDEA process, particularly when the syngas pressure is high and deep sulfur removal is required (e.g., down to 10-20 ppmv). (3) The refrigeration and complexity of the chilled methanol process make it the most expensive AGR process, and accordingly, its use is generally restricted to applications in which almost pure syngas (containing as low as
