Syngas Cleanup

MERCURY/TOXICS EMISSIONS

Overview
Assessment of the environmental performance of coal-based integrated gasification combined cycle (IGCC) technology indicates that vapor-phase mercury (Hg) emissions may need to be further reduced to comply with future U.S Environmental Protection Agency (EPA) mercury regulations. The purpose of this section is to examine both commercial and near-commercial methods for integrating such control into a typical IGCC system.

Two basic approaches for control are: 1) turbine exhaust gas treatment and 2) syngas treatment. While vapor-phase mercury can potentially be removed from the flue gas exiting the gas turbine/heat recovery steam generator (HRSG), it is more effective in IGCC systems to remove Hg from the syngas prior to combustion. This may already occur, to some extent, via the acid gas scrubbing system, but more data are required to verify this. Syngas removal has the advantage of higher mercury concentration, lower mass flow rates, and higher pressure than the stack gas. Disadvantages include operation in a reducing environment (more corrosive environment), possible operation at a high temperature if part of a hot gas cleanup system, possible presence of other contaminants, and greater safety issues related to premature combustion. A review of syngas control options revealed that several commercially available technologies, using sorbents such as activated carbon, have already been successfully applied to gasification applications, as well as other gaseous hydrocarbon streams. These are discussed below.

UOP Corporation has a commercial product that is in wide use in natural gas/natural gas liquids and LNG (liquefied natural gas) plants called HgSIV. It is a molecular sieve (MS) that removes very low levels of elemental mercury from natural gas or syngas via a regenerable adsorption process. It uses a 2-bed thermal-swing MS adsorption system. The gas flows through one adsorbent bed to adsorb Hg, while the temperature of the other bed rises to desorb Hg. After regeneration, the beds are reversed. Hg removal is needed in NGL or LNG plants to protect the braised aluminum heat exchangers in the cryogenic section from mercury attack. HgSIV has been successfully operated in about 30 plants for almost 10 years1.

Eastman Chemical Company has developed and successfully applied activated carbon-based mercury control technology at their Chemicals from Coal Facility located in Kingsport, Tennessee2. Eastman has been operating GE Energy (formerly ChevronTexaco gasifiers) at this facility since 1983 to provide syngas for the production of acetyl chemicals. They utilize Calgon’s HGR-P sulfur-impregnated, pelleted activated carbon beds with the following performance characteristics:

  • Operating conditions: Approximately 30°C (86°F) and 900 psi
  • Gas contact time in bed: Approximately 20 seconds (based on total packed volume)
  • Removal efficiency: Ranges from 90-95%
  • Carbon lifetime: 12 to 18 months based on a buildup in pressure drop, a buildup in water in the bed, or a buildup of other contaminants.

Eastman Chemical operates their carbon beds ahead of the sulfur recovery unit. The use of dual beds, (i.e., two beds in series) should be capable of achieving carbon removal levels of greater than 99%.

Sorbents for Mercury Capture
A number of companies produce activated carbons that have been used commercially for mercury removal from combustion flue gas, with most of the applications being for incinerator stack gas. Norit’s DARCO® Hg series of lignite-derived activated carbons are manufactured specifically for the removal of heavy metals and other contaminants typically found in utility flue gas3. It has been proven in numerous full-scale facilities to be highly effective for the removal of gaseous mercury, dioxins (PCDD) and furans (PCDF). Its open pore structure and fine particle size permit rapid adsorption, which is critical for high performance in gas streams where contact times are short. It is a free flowing powdered carbon with minimal caking tendencies that makes it appropriate for automatic wet or dry injection systems. It has a very high ignition temperature, which permits safe operation at the elevated temperatures inherent in incinerator flue gas. This material has also been successfully used in a number of R&D programs focused on evaluation of mercury removal from coal-fired power plant stack gas.

UOP has developed several commercial mercury sorbents, including the copper on alumina GB adsorbents, and a line of zeolite-based desiccants called HgSIV modified with silver for enhanced mercury removal capability. Zeolites are crystalline structures not unlike sponges on a molecular scale. They have a solid framework defining large internal cavities where molecules can be adsorbed. These cavities are interconnected by pore openings through which molecules can pass. Because of their crystalline nature, the pores and cavities are all precisely the same size, and depending on the size of the openings, they can adsorb molecules readily, slowly, or not at all, thus functioning as molecular sieves -- adsorbing molecules of certain sizes while rejecting larger ones. UOP indicates that their HgSIV products have proven to be reliable in removing mercury from natural gas, natural gas liquids, and other process streams such as ethylene4.

Calgon Carbon’s family of FluePac® powdered activated carbons is specially manufactured for use in flue gas treatment5. Their high effective surface area and large pore volume make them extremely effective in removing common contaminants, including mercury, dioxins, furans, and volatile organic compounds (VOCs). Typical applications include municipal waste combustors, hazardous waste combustors, hospital waste incinerators, coal-fired power plants, cement kilns, and industrial boilers. These coal-derived powdered activated carbons have a high minimum Iodine Number (measurement of available surface area) with up to twice the amount of high-energy adsorption sites compared to other adsorbent carbons. With proper dosing levels, Calgon claims that over 95 percent reduction in mercury/dioxin is achievable. This sorbent has been used by Eastman Chemical Company in their gasification facility to control mercury.

Use of these sorbents for mercury control may also provide the added side benefit of residual hydrogen sulfide (H2S) removal, which could improve IGCC integration with add-on nitrogen oxides (NOx) control technologies such as selective catalytic reduction (SCR). However, their effectiveness for this purpose has to be verified.

Cost of Mercury Control Based on Activated Carbon Adsorption
NETL’s own cost and performance baselines for IGCC plant configurations provide information on cost of mercury control in this context. As an example, the bituminous coal to electricity IGCC cases assume that activated carbon beds would be used, with performance data derived from the experience of Eastman Chemical Company’s syngas facility in Kingsport, Tennessee as discussed previously. Assumptions were Illinois #6 coal with 0.15 ppm dry mercury content, packed carbon bed vessels (Calgon carbon) located upstream of the sulfur recovery unit, with syngas entering the beds at a temperature near 38°C (100°F), carbon bed removal efficiency of 95 percent, which would meet targeted emissions levels (actual emissions would be 4.16 x 10-6 lb/MWh, considerably less than the NSPS limit of 20 x 10-6 lb/MWh), and gas velocity, carbon replacement frequency, and other process parameters mirroring the practices at the Eastman syngas facility. For a GE Energy gasifier-based IGCC plant producing net power of 622 MWe without carbon capture, total plant capital cost for the mercury removal system is estimated to be $2,561,000 or $4.11/kW. Initial activated carbon cost is $58,000 with annual replenishment cost of ~$23,000 assuming a $1.05/lb cost of the carbon, while disposal cost of the hazardous spent carbon sorbent is ~$9,000 per year.

New Emissions Limits on Mercury and Air Toxics
Subsequent to the release of the NETL baselines, stringent regulations have been enacted for trace contaminant emissions from IGCC systems. Specifically, the U.S. Environmental Protection Agency’s (EPA) December 21, 2011, Mercury and Air Toxics Standards (MATS), the first national standards for mercury (Hg) pollution from power plants, require existing power plants to reduce Hg pollution by 90%, reduce acidic gases (hydrogen chloride [HCl] and hydrogen fluoride [HF]) by 88%, and substantially reduce other pollutants by 2015.6 Moreover, MATS requires new/in-construction power plants to conform to even higher standards of upwards of 99.9%. These have been officially reconsidered, with EPA issuing a notice of final action on reconsideration on March 28, 2013. In June 2013 40 CFR Parts 60 and 63 were published in the Federal Register, which finalized reconsideration of all the issues included in the proposed rule except those related to facilities startup and shutdown, with the EPA reopening the public comment period for the proposed reconsideration to solicit additional input on startup and shutdown and to request comment on the additional technical analyses it conducted.7 EPA has reported that implementation to meet proposed revised standards will be essentially the same as that which would have been chosen in complying with the original MATS rule.8 The U.S. Department of Energy (DOE) targets for trace contaminant removals are also stringent in order to avoid poisoning: (1) the catalysts essential for making liquids from fuel gas, (2) the electrodes in fuel cells, and (3) the selective catalytic reduction (SCR) catalysts employed in coal- or gas-burning power plants.

The EPA MATS requirement for Hg emissions of new IGCC-based power plants is 3 x 10-6 lb/MWh gross power output (~2 ppbw). This is considerably more stringent than the former NSPS limit of 20 x 10-6 lb/MWh to which the NETL baselines were ascribing. However, those baselines also assumed 95% mercury removal, which brought their actual Hg emission rates into the 4 to 5 x 10-6 lb range, nearly meeting the new MATS requirements, while recovery of mercury to 99% would still be possible with activated carbon; the higher recovery percentage would bring the emissions rates well under the MATS limits.

Mercury Control in High Temperature Syngas Cleanup
Capture of Hg and other trace metal/toxic contaminants (arsenic [As], selenium [Se], cadmium [Cd], antimony [Sb], and phosphorus [P]) in syngas is optimal at lower temperatures; the types of carbon sorbents in the foregoing discussion are generally intended for utilization in near-ambient temperature removal of Hg from natural gas and syngas and for removal of Hg from flue gas at temperatures up to 350°F.9,10,11,12,13,14,15 However, these sorbents have been reported to be unsatisfactory for Hg removal at temperatures exceeding 400°F.16,17,18 In fact, few sorbents have been shown to remove Hg from high-temperature syngas because: 1) the physical adsorption of Hg on a sorbent typically decreases with increasing temperature; 2) Hg compounds formed on the surface of a sorbent can thermally decompose or desorb at high temperatures; and 3) chemical promoters, such as sulfur or halogens, will desorb from the sorbent at elevated temperatures. In addition to these problems, carbon-based sorbents lack the desirable chemical resistance and regeneration capability properties for warm-gas cleanup (WGCU).19

Unfortunately, the limitations of current sorption technologies based on activated carbons are at odds with efforts to develop and implement high-temperature, or WGCU of syngas, which would boost the thermal efficiency of IGCC plants. WGCU would have the additional benefits of removing toxic contaminants from warm syngas nearer the gasifier exit, helping to eliminate the circulation of dirty water and treatment systems downstream in IGCC plants; reducing the footprint, cost, and complexity of the systems; and ensuring the disposition of trace metal pollutants so that they will not contaminate process equipment, poison raw materials, or foul catalysts or fuel cells.20,21,22,23 Accordingly, the identification and development of a durable sorbent material capable of effectively and efficiently removing Hg and other trace metals at both elevated temperatures and pressures characteristic of actual process conditions have been a high priority.

Drawing on previous experience with sorbents in coal combustion flue gas, NETL has selected potential high-temperature candidate sorbents, developed a process for testing the various candidate sorbents at bench-scale in simulated WGCU, and determined the capacities of the sorbents for capture of Hg, As, Se, and P. Palladium (Pd)-based sorbents are currently among the most promising candidates, as they have been found to effectively capture trace contaminants such as Hg, As, Se, and P from syngas at elevated temperatures (400 to 700°F).24 The sorbents are described in U.S. patent 7,033,419, issued in April 2006. A license agreement between NETL and Johnson Matthey (JM) for further research, development, and commercialization of the sorbents for application in IGCC and in chemicals production from syngas was signed in March 2007. Collaboration between JM and NETL resulted in thorough characterization and bench-scale tests of these Pd sorbents,25,26,27 including testing of the sorbent in slipstreams of dirty fuel gas that began in 2009. More recent tests of the technology at larger-scale have taken place at Southern Company’s Power Systems Development Facility at the National Carbon Capture Center. Results have been highly promising, with more than 99% removal of Hg, As, and Se from dirty fuel gas slipstreams at 550°F over long periods (several weeks).


  1. Kubek, D., Information contained in e-mail from Dan Kubek of UOP to Jim Childress of the Gasification Technology Council, May 24, 2001.
  2. Denton, D., Eastman Chemicals Company presentation at Gasification Technology Council Workshop, September 11, 2001.
  3. Norit website, Last visited March 2014.
  4. UOP Corporation website. Last visited March 2014.
  5. Calgon Carbon Corporation website. Last visited Sep 2014.
  6. Environmental Protection Agency, in 77; National Archives and Records Administration: Federal Register, 2012; p. 9303.
  7. Environmental Protection Agency, 40 CFR Parts 60 and 63, EPA–HQ–OAR–2009–0234; EPA–HQ–OAR–2011–0044, FRL–9827–1, RIN 2060–AR62, “Reconsideration of Certain Startup/Shutdown Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units,” accessed 7 Apr 2014.
  8. Environmental Protection Agency, in 40 CFR Parts 60 and 63; Federal Register: Washington, DC, November 30, 2012; Vol. EPA-HQ-OAR-2009-0234, EPA-HQ-OAR-2011-0044, FRL-9733-2, p. 71323.
  9. Poulston, S.; Granite, E. J.; Pennline, H. W.; Myers, C. R.; Stanko, D. P.; Hamilton, H.; Rowsell, L.; Smith, A. W. J.; Ilkenhans, T.; Chu, W. Fuel 2007; 86: 2201.
  10. Wendt, J. O. L., Lee, Sung Jun Fuel 2010; 89: 894.
  11. Granite, E. J., Pennline, Henry W., Hargis, Richard A. Industrial & Engineering Chemistry Research 2000; 39: 1020.
  12. Reed, G. P.; Ergüdenler, A.; Grace, J. R.; Watkinson, A. P.; Herod, A. A.; Dugwell, D.; Kandiyoti, R. Fuel 2001; 80: 623.
  13. Wu, S., Uddin, Md. Azhar, Sasaoka, Eiji Fuel 2006; 85: 213.
  14. Zhang, H., Zhao, J., Fang, Y., Huang, J., Want, Y. Energy & Fuels 2012; 26: 1629.
  15. McNamara, J. D., Wagner, N.J. Gas Separation and Purification 1996; 10: 137.
  16. Granite, E. J., Pennline, Henry W., Hargis, Richard A. Industrial & Engineering Chemistry Research 2000; 39: 1020.
  17. Granite, E. J.; Myers, C. R.; King, W. P.; Stanko, D. C.; Pennline, H. W. Industrial & Engineering Chemistry Research 2006; 45: 4844.
  18. Poulston, S.; Granite, E. J.; Pennline, H. W.; Hamilton, H.; Smith, A. W. J. Fuel 2011; 90: 3118.
  19. Reed, G. P.; Ergüdenler, A.; Grace, J. R.; Watkinson, A. P.; Herod, A. A.; Dugwell, D.; Kandiyoti, R. Fuel 2001; 80: 623.
  20. Quinn, R., Mebrahtu, T., Dahl, T.A., Lucrezi, F.A., Toseland, B.A. Applied Catalysis A: General 2004; 264: 103.
  21. Coade, R., Coldham, D. International Journal of Pressure Vessels and Piping 2006; 83: 336.
  22. Nichols, H., Rostoker, W. Acta Metallurgica 1961; 9: 504.
  23. Cayan, F. N., Zhi, M., Pakalapati, S.R., Celik, I., Wu, N., Gemmen, R. Journal of Power Sources 2008; 185: 595.
  24. Granite, E. J.; Myers, C. R.; King, W. P.; Stanko, D. C.; Pennline, H. W. Industrial & Engineering Chemistry Research 2006; 45: 4844.
  25. Poulston, S.; Granite, E. J.; Pennline, H. W.; Myers, C. R.; Stanko, D. P.; Hamilton, H.; Rowsell, L.; Smith, A. W. J.; Ilkenhans, T.; Chu, W. Fuel 2007; 86: 2201.
  26. Poulston, S.; Granite, E. J.; Pennline, H. W.; Hamilton, H.; Smith, A. W. J. Fuel 2011; 90: 3118.
  27. Baltrus, J. P.; Granite, E. J.; Pennline, H. W.; Stanko, D.; Hamilton, H.; Rowsell, L.; Poulston, S.; Smith, A.; Chu, W. Fuel 2010; 89: 1323.

Syngas Clean Up

 

Gasifipedia Home
StayConnected Facebook Twitter LinkedIn RssFeed YouTube