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Energy & Fuels 2008, 22, 3824–3837
Novel Physical Solvents for Selective CO2 Capture from Fuel Gas Streams at Elevated Pressures and Temperatures† Yannick J. Heintz,‡,§ Laurent Sehabiague,§ Badie I. Morsi,*,‡,§ Kenneth L. Jones,‡ and Henry W. Pennline‡ National Energy Technology Laboratory, United States Department of Energy (DOE), Post Office Box 10940, Pittsburgh, PennsylVania 15236, and Chemical and Petroleum Engineering Department, UniVersity of Pittsburgh, Pittsburgh, PennsylVania 15261 ReceiVed February 7, 2008. ReVised Manuscript ReceiVed April 16, 2008
Three perfluorinated compounds (PFCs), PP10, PP11, and PP25, manufactured by F2 Chemicals Ltd., U.K., were investigated as physical solvents for selective CO2 capture from synthesis gas or syngas streams at elevated pressures and temperatures. The equilibrium solubility, the hydrodynamic, and the mass-transfer parameters of CO2 in the solvents were measured in a 4-L ZipperClave agitated reactor under wide ranges of operating conditions: pressures (6-30 bar), temperatures (300-500 K), mixing speeds (10-20 Hz), and liquid heights (0.14-0.22 m). The CO2 solubilities in the three solvents decreased with an increasing temperature at constant pressure and followed Henry’s law. The CO2 solubilities in PP25 were greater than those in PP10 and PP11. The volumetric liquid-side mass-transfer coefficients (kLa) of CO2 in the PFCs increased with mixing speed, pressure, and temperature. Also, the gas-liquid interfacial areas of CO2 in the three PFCs appeared to control the behavior of kLa. This study proved the thermal and chemical stability and the ability of the PFCs to selectively absorb CO2 at temperatures up to 500 K and pressures as high as 30 bar. A preliminary conceptual process design using PP25 for selective CO2 capture from hot-shifted gas with pressure-swing and pressure-temperatureswing regeneration options was devised [a temperature-swing option was also examined but is not reported here because it is outside the context of the present study, which involves a physical solvent process benchmark (Selexol) for which temperature-swing regeneration is not a viable option]. The pressure-temperature-swing option led to greater PP25 solvent loss but a more favorable (more negative) net enthalpy than the pressureswing option. However, for either regeneration option to be economically viable, the PP25 solvent must be completely recovered from the process.
1. Introduction Carbon dioxide (CO2), considered the major greenhouse gas (GHG) generated by human activities, is mainly produced by combustion of fossil fuels used in power generation facilities, manufacturing industries, and transportation vehicles. Projections made by the International Energy Agency (IEA) indicated that fossil fuels will remain the dominant source of energy until 2030 and will play a major role in the years to follow.1 In an effort to mitigate CO2 emissions, the United States Department of Energy is expected by the year 2012 to develop commercial fossil fuel conversion systems, which would remove at least 90% of CO2 while keeping the increase in the cost of electricity below 10% for precombustion techniques.2 One vision of such innovative clean energy is to produce power from coal using the integrated gasification combined cycle (IGCC). IGCC power generation facilities enjoy several advantages over coal-fired facilities, such as (1) the discharge of solid byproducts and † Disclaimer: Reference in this paper 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:
[email protected]. ‡ United States Department of Energy (DOE). § University of Pittsburgh. (1) Gale, J.; Bachu, S.; Bolland, O.; Xue, Z. To store or not to store. Int. J. Greenhouse Gas Control 2007, 1 (1), 1. (2) Plasynski, S.; Deel, D.; Miller, L.; Kane, B. Carbon sequestration technology roadmap and program plan. U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, April 2007.
wastewater is reduced by about 50%; (2) the emission of pollutant (NOx, SOx, CO, etc.) is much lower; (3) the emission of trace hazardous air pollutants, including gaseous mercury (Hg), is lower; and (4) the CO2 emission is reduced by at least 10% per equivalent net production of electricity.3 The CO2 emission from IGCC facilities, however, is indisputably the largest contributor to the GHG when compared to the other produced gases, including N2O and NH3. Fortunately, the IGCC is remarkably suited for near total CO2 removal for subsequent sequestration.3–6 This is because CO2 can be captured more efficiently from IGCC than from a pulverized-coal combustion facility because of the following reasons: (1) the fuel gas streams have higher CO2 concentration, which can be further increased (3) Ratafia-Brown, J. A.; Manfredo, L. M.; Hoffmann, J. W.; Ramezan, M.; Stiegel, G. J. An environmental assessment of IGCC power systems. Proceedings of the 19th Annual International Pittsburgh Coal Conference, Pittsburgh, PA, Sept 23-27, 2002; pp 235-250. (4) White, C. M.; Strazisar, B. R.; Granite, E. J.; Hoffman, J. S.; Pennline, H. W. Separation and capture of CO2 from large stationary sources and sequestration in geological formationssCoalbeds and deep saline aquifers. J. Air Waste Manage. Assoc. 2003, 53 (6), 645–715. (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 739656-00100. (6) Gielen, D. The energy policy consequences of future CO2 capture and sequestration technologies. Paper prepared for the 2nd Annual Conference on Carbon Sequestration: Developing and Validating the Technology Base to Reduce Carbon Intensity, Alexandria, VA, May 5-8, 2003.
10.1021/ef800091e CCC: $40.75 2008 American Chemical Society Published on Web 09/10/2008
NoVel Physical SolVents for SelectiVe CO2 Capture
by converting more CO into CO2 prior to combustion while producing more hydrogen through the water-gas shift (WGS) reaction; and (2) the IGCC gasifier typically operates under relatively high pressure, producing a higher partial pressure of CO2 and thus making CO2 capture from the shifted fuel gas stream much easier than from the flue gas stream. The concentrated CO2 in the shifted fuel gas streams can actually be removed by one of the proven acid gas removal (AGR) processes, varying from disposable/regenerable solid sorbent types to regenerable solvent types. Despite the fact that elevated CO2 capture capacities from simulated combustion and gasification gas streams were claimed for various solid sorbents, such as zeolites, these systems remain energy-intensive and therefore penalize the plant’s overall efficiency. Currently, solvent-type processes are used for AGR from fuel gas3,4 because of their potential minimal impact on the overall efficiency of the power plant. In 2000, a study by EPRI7 concluded that 75% of the CO2 could be captured from IGCC power generation facilities with only 4% loss in the overall efficiency, without accounting for the cost of CO2 transportation to use/sequestration sites or further processing. The solventtype processes can be categorized into chemical, physical, and mixed chemical/physical ones. The chemical processes mainly use amines, such as methyl-diethanol amine (MDEA). The wellknown physical processes employ different solvents, such as chilled methanol (Rectisol), a mixture of dimethyl ethers of polyethylene glycol (Selexol) and n-formylmorpholine/n-acetylmorpholine (Morphysorb). The mixed chemical/physical processes use Sulfinol (a mixture of sulfolane and aqueous solution of either di-isopropanol amine (DIPA) or MDEA).4–6,8 A comparison among the chemical and physical processes used for desulfurization reveals the following:5 (1) the MDEA process has higher heat requirements for solvent regeneration than physical solvent processes; (2) the Selexol process is more expensive than the MDEA process; however, it could be more cost-effective than the MDEA process, particularly, when the syngas pressure is high and deep sulfur removal is required; and (3) the refrigeration of the Rectisol process makes it the most expensive process, and therefore, its use is generally reserved for applications where almost pure syngas, containing
