Regenerable Manganese-Based Sorbent for Cleanup of Simulated

Jan 5, 2011 - C.F.J. König , M. Nachtegaal , M. Seemann , F. Clemens , N. van Garderen , S.M.A. Biollaz , T.J. Schildhauer. Applied Energy 2014 113, ...
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Energy Fuels 2011, 25, 379–387 Published on Web 01/05/2011

: DOI:10.1021/ef101337v

Regenerable Manganese-Based Sorbent for Cleanup of Simulated Biomass-Derived Syngas Singfoong Cheah,* Jessica L. Olstad, Whitney S. Jablonski, and Kimberly A. Magrini-Bair National Bioenergy Center, National Renewable Energy Laboratory, 1617 Cole Boulevard, MS 3322, Golden, Colorado 80401, United States Received September 30, 2010. Revised Manuscript Received December 10, 2010

During biomass gasification, sulfur contained in the feedstock is converted primarily to hydrogen sulfide. Conventional technologies for sulfur removal such as amine scrubbing and ZnO sorption operate at much lower temperatures than those of gasification and tar reforming and are thus thermally inefficient for cleanup of biomass-derived syngas. This work aims to develop options for high-temperature sulfur removal. In this research, we focus our investigation on the regeneration chemistry of a manganese-based sorbent for sulfur removal at the high temperature, high steam conditions (700 °C and up to 68% steam) used for biomass gasification and subsequent syngas conditioning. We found that regeneration conditions that have a small amount of air or steam in combination with air would allow for equal sulfidation and regeneration time. We also demonstrated the effectiveness of both fresh and regenerated sorbents in protecting downstream tar and methane reforming catalysts.

Hydrogen sulfide content in raw biomass-derived syngas varies with feedstock, ranging from 20-100 ppmv for wood3,8,9 to 300-600 ppmv for herbaceous feedstocks.3 Previous studies of nickel based tar and methane steam reforming catalysts used to condition biomass syngas have shown that the catalyst deactivated quickly and required frequent regeneration.4,8,10 Precious metal catalysts such as platinum and rhodium are known to have good sulfur tolerance11 in a variety of applications. However, the initial start-up cost of using precious metals is high. Consequently, it is considered impractical to use precious metal catalysts for commercial steam reforming plants.12 For large scale conversion of biomass to biofuels or electricity, it is likely more economical to use nonprecious metal catalysts. To preserve the catalyst activity of nonprecious metals, it is essential that contaminants be removed from the syngas. There are several commercial methods to remove H2S from raw syngas, e.g., via low temperature amine scrubbers or ZnO sorbent. The amine scrubbing process requires lowering the temperature of the syngas from 850 °C (temperature of gasification) to 40-50 °C for cleanup13 with concurrent tar condensation. Tar condensation makes condenser operation challenging, reduces biomass carbon utilization, and produces a large waste stream that must be treated. The process is also thermally inefficient, and though theoretically the heat energy can be partially recovered using heat exchange equipment, tar build up on reactor walls during condensation could render

1. Introduction Production of biofuels from biomass feedstocks, in particular, those derived from agricultural lignocellulosic residues, represents a path that is carbon neutral and is potentially cost competitive with other transportation fuel production processes. Gasification of biomass to a product gas rich in syngas, followed by conversion of the product gas to biofuel, represents a relatively mature and promising route.1,2 However, the product gas generated from biomass feedstock gasification contains inorganic species, including hydrogen sulfide (H2S),3 which can cause severe downstream processing problems. Sulfur needs to be removed because sulfur-containing gases are corrosive; are precursors to SO2, a regulated emission gas; and deactivate catalysts used in downstream processes.4-7 The downstream catalysts can include nickel catalysts used for tar reforming, copper catalysts used in water gas shift, as well as iron and cobalt catalysts used in Fischer-Tropsch fuel synthesis.

*To whom correspondence should be addressed. Telephone: (303)384-7707. Fax: (303)384-6363. E-mail: Singfoong.cheah@nrel. gov. (1) Foust, T. D.; Aden, A.; Dutta, A.; Phillips, S. Cellulose 2009, 16 (4), 547–565. (2) Phillips, S. D. Ind. Eng. Chem. Res. 2007, 46 (26), 8887–8897. (3) Carpenter, D. L.; Bain, R. L.; Davis, R. E.; Dutta, A.; Feik, C. J.; Gaston, K. R.; Jablonski, W.; Phillips, S. D.; Nimlos, M. R. Ind. Eng. Chem. Res. 2010, 49 (4), 1859–1871. (4) Bain, R. L.; Dayton, D. C.; Carpenter, D. L.; Czernik, S. R.; Feik, C. J.; French, R. J.; Magrini-Bair, K. A.; Phillips, S. D. Ind. Eng. Chem. Res. 2005, 44 (21), 7945–7956. (5) Hepola, J.; McCarty, J.; Krishnan, G.; Wong, V. Appl. Catal., B: Environ. 1999, 20 (3), 191–203. (6) Hepola, J.; Simell, P. Appl. Catal., B: Environ. 1997, 14 (3-4), 287– 303. (7) Hepola, J.; Simell, P. Appl. Catal., B: Environ. 1997, 14 (3-4), 305– 321. (8) Cui, H.; Turn, S. Q.; Keffer, V.; Evans, D.; Tran, T.; Foley, M. Energy Fuels 2010, 24 (2), 1222–1233. (9) Sato, K.; Shinoda, T.; Fujimoto, K. J. Chem. Eng. Jpn. 2007, 40 (10), 860–868. r 2011 American Chemical Society

(10) Yung, M. M.; Magrini-Bair, K. A.; Parent, Y. O.; Carpenter, D. L.; Feik, C. J.; Gaston, K. R.; Pomeroy, M. D.; Phillips, S. D. Catal. Lett. 2010, 134 (3-4), 242–249. (11) Tomishige, K.; Miyazawa, T.; Kimura, T.; Kunimori, K.; Koizumi, N.; Yamada, M. Appl. Catal., B: Environ. 2005, 60 (3-4), 299–307. (12) Bartholomew, C. H.; Farrauto, R. J. Fundamentals of Industrial Catalytic Processes, 2nd ed.; Wiley-Interscience: Hoboken, NJ, 2006. (13) Phillips, S.; Aden, A.; Jechura, J.; Dayton, D.; Eggeman, T. Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass; NREL/TP-510-41168; National Renewable Energy Laboratory: Golden, CO, April 2007; www.nrel.gov/docs/ fy07osti/41168.pdf.

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the heat recovery challenging. Technoeconomic analysis has indicated the amine scrubbing process is best suited for a very large scale operation. In an alternate route, the syngas needs to be lowered to 300-400 °C for sulfur removal using ZnO. Higher temperatures do not remove H2S to sufficiently low levels;8 additionally, zinc vaporization causes problems at high temperatures.14 The scrubbed gas would then need to be reheated to 800 °C for catalytic tar and methane reforming.8 This cooling and reheating of the syngas is both thermally inefficient and expensive. This work focuses on developing high temperature sulfur sorbents for biomass syngas applications and may provide an economically competitive option by allowing gasification, gas clean up, and downstream processes to operate at similar temperatures.15 We use literature information of sorbents developed for coal-derived syngas at mid- to high- temperature ranges as the starting point in our sorbent synthesis and testing. Most of the sorbents that have been developed for the coal gas industry are based on the solid-gas reaction between a metal oxide (MO) and H2S: MOðsÞ þ H2 SðgÞ S MSðsÞ þ H2 OðgÞ

Figure 1. (a) Phase diagram of the Mn-S-O system at 700 °C. (b) Results of thermodynamic modeling of H2S concentrations in equilibrium with Mn2O3 as a function of temperature and humidity.

ðReaction 1Þ

Because a number of promising oxides such as iron-, cobalt, and copper-based materials readily reduce to lower oxidation states and lose activities or active materials in the highly reducing syngas environment at high temperature,16 the focus of the research in the last 2 decades has been on producing materials that are stable in this challenging environment. The research efforts found sorbents based on zinc titanate17-20 and manganese-21-24 and rare earth-based materials25-28 are promising for the “high” temperature region (>600 °C). Calcium-based sorbents can also work in the high temperature region, but the residual sulfur can be up to 100 ppmv and the strength of the calcium-based materials also needs to be improved.15 In the “mid” temperature ranges (400-600) °C,

copper- and iron-containing mixed oxides29-31 as well as zinc oxide stabilized with alumina or iron oxide17,32 are found to be effective. Even though significant progress has been achieved in research on desulfurizing coal derived syngas, cleaning up biomass-derived syngas involves some unique challenges and advantages. Coal gasification is usually a direct oxygen- or air-blown process conducted at higher temperature than biomass gasification. Consequently, the coal syngas that is produced usually has low water and hydrocarbon content. In contrast, indirect biomass gasification, often conducted with steam and air as gasifying agents, results in a biomass syngas that has higher steam (30-65%)13,33-35 and hydrocarbon content (e.g., 12-16% for methane on a dry basis contents3). In the literature, even though there are many reports of sulfur sorbent use for dry syngas cleaning, there are very few studies involving high temperature sorbents for cleaning up syngas containing high steam and relatively high hydrocarbon content. It is clear that a high concentration of water molecules reduces the extent of sulfidation of a metal oxide, and the reaction will proceed only if the sorbent has a very large equilibrium constant for Reaction 1. Figure 1a shows the phase diagram of the Mn-S-O system. Figure 1b shows that H2S levels in thermodynamic equilibrium with a Mn2O3

(14) Gibson, J. B., III; Harrison, D. P. Ind. Eng. Chem. Process Des. Dev. 1980, 19 (2), 231–237. (15) Cheah, S.; Carpenter, D. L.; Magrini-Bair, K. A. Energy Fuels 2009, 23 (11), 5291–5307. (16) Swisher, J. H.; Schwerdtfeger, K. J. Mater. Eng. Perform. 1992, 1 (3), 399–408. (17) Lew, S.; Jothimurugesan, K.; Flytzani-Stephanopoulos, M. Ind. Eng. Chem. Res. 1989, 28, 535–541. (18) Gangwal, S. K.; Harkins, S. M.; Woods, M. C.; Jain, S. C.; Bossart, S. J. Environ. Prog. 1989, 8 (4), 265–269. (19) Siriwardane, R. V.; Poston, J. A. Appl. Surf. Sci. 1990, 45 (2), 131–139. (20) Gupta, R. P.; Turk, B. S.; Portzer, J. W.; Cicero, D. C. Environ. Prog. 2001, 20 (3), 187–195. (21) Ben-Slimane, R.; Hepworth, M. T. Energy Fuels 1994, 8, 1175– 1183. (22) Ben-Slimane, R.; Hepworth, M. T. Energy Fuels 1994, 8, 1184– 1191. (23) Ben-Slimane, R.; Hepworth, M. T. Energy Fuels 1995, 9 (2), 372– 378. (24) Bakker, W. J. W.; Kapteijn, F.; Moulijn, J. A. Chem. Eng. J. 2003, 96 (1-3), 223–235. (25) Kay, D. A. R.; Wilson, W. G. J. Metals 1988, 40 (11), 57. (26) Li, Z. J.; Flytzani-Stephanopoulos, M. Ind. Eng. Chem. Res. 1997, 36 (1), 187–196. (27) Zeng, Y.; Zhang, S.; Groves, F. R.; Harrison, D. P. Chem. Eng. Sci. 1999, 54 (15-16), 3007–3017. (28) Dooley, K.; Adusumilli, S.; Forest, R. In Mesoporous Mixed Rare Earth Oxides for Hot Gas Desulfurization, Tar Cracking and Nanoparticle-Aided Combustion; AIChE: Nashville, TN, November 8-13, 2009. (29) Tamhanker, S. S.; Bagajewicz, M.; Gavalas, G. R.; Sharma, P. K.; Flytzani-Stephanopoulos, M. Ind. Eng. Chem. Process Des. Dev. 1986, 25, 429–437.

(30) Abbasian, J.; Slimane, R. B. Ind. Eng. Chem. Res. 1998, 37 (7), 2775–2782. (31) Siriwardane, R. V.; Poston, J. A. Appl. Surf. Sci. 1993, 68 (1), 65–80. (32) Gangwal, S. K.; Stogner, J. M.; Harkins, S. M.; Bossart, S. J. Environ. Prog. 1989, 8 (1), 26–34. (33) Boerrigter, H.; Rauch, R. Review of Applications of Gases from Biomass Gasification; Vienna Institute of Technology: The Netherlands, June 2006; http://www.ecn.nl/docs/library/report/2006/rx06066.pdf. (34) Milne, T. A.; Evans, R. J.; Abatzoglou, N. Biomass gasifier tars: their nature, formation, and conversion; NREL/TP-570-25357; National Renewable Energy Laboratory: Golden, CO, November 1998; http://www. nrel.gov/docs/fy99osti/25357.pdf. (35) Torres, W.; Pansare, S. S.; Goodwin, J. G., Jr. Catal. Rev.-Sci. Eng. 2007, 49, 407–456.

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sorbent in a syngas atmosphere as calculated using HSC 6.1, a thermodynamic modeling software. HSC calculated the multicomponent equilibrium compositions in the heterogeneous system using the Gibbs energy minimization method of all the potential reactions between the input species. The input species for the calculation were 10.6% CO, 10.5% H2, 6.3% CH4, 8.3% CO2, 1.7% C2H4, 370 ppmv benzene, 390 ppmv H2S, with the balance being N2 and steam (N2 and steam were varied to achieve the various steam levels). The solid phase was in excess. The calculation results show that H2S level increases with moisture content and with temperature (Figure 1b). Reaction 1 and Figure 1b show that the high steam content of biomass derived syngas presents a significant challenge in sorbent material development. For this work, we focus on manganese-based material, one of the sorbents that is promising for high temperature, high steam environments. Two previous estimates on the impact of high-temperature sorbent cost on electricity production (both studies focused on the coal to syngas, then electricity generation process) suggest that sorbent cost, replacement rate, and regeneration all affect the electricity cost.27,36 The regenerability of the sorbent may affect the economics of the biomass to liquid fuels conversion process, and therefore sorbent regeneration is studied in detail in this research. Literature results contain conflicting information on the “best” regeneration conditions for the sorbents. Many studies of different sorbents (not just manganese-based) have shown that the kinetics of oxidative-type regeneration are faster than regeneration that extracts sulfur using steam or hydrogen.15,22 However, the presence of oxygen can promote sulfate formation,37 which is generally accepted as detrimental to the long-term sulfur removal capacity of the material. This is because sulfate is challenging to decompose, and it is hypothesized that the large volume difference between sulfate and oxide would cause the active sorbent material to “break up” after repeated sulfidation and regeneration cycles. Alonso and Palacios, however, observed sulfate formation in their study of a durable Zn-doped manganese oxide and hypothesized that the presence of some sulfate helps to prevent loss of pore structure.38 It should be noted that the sorbent did become inactive after regeneration in pure air (20% oxygen). In a separate study on a Mn-Fe-Zn-O mixed oxide sorbent by Zhang et al., levels of oxygen in the range of 6-8%, which would have promoted sulfate formation, were used for regeneration and the sorbent kept its activity during 30 cycles of sulfidation and regeneration.39 The uncertainty of the potential negative impacts of sulfate still requires further investigation. On the basis of thermodynamic modeling, Ben-Slimane and Hepworth concluded that regeneration of manganese-based sorbents needs to be conducted at a temperature that is > 915 °C to avoid sulfate formation.21-23 Karayilan et al., however, found that a Mn-Cu mixed sorbent needs to be regenerated at a lower temperature, between 700 and 800 °C to retain its activity. They observed that regeneration at temperature above 800 °C resulted in sintering and loss of activity.40

The general conclusions based on literature results were that at least some levels of oxidative species, e.g., CO2, O2, are useful for improved kinetics. Steam is commonly used because it promotes the reverse of Reaction 1. The temperature would ideally be not so high that it would cause sintering and loss of activity. In our system, it would be economically advantageous to be able to conduct isothermal regeneration, therefore for all but one set of regeneration experiments reported here, the regeneration and sulfidation temperature is equal. In this work, our focus is to develop an understanding of the predominant regeneration chemistry, to use X-ray diffraction characterization studies to determine the sulfur removal mechanism(s), and to use the information gained to design more effective, lower cost sorbents in the future. In a separate publication, we will be focusing on determining under what conditions the effect of steam on sorption can be quantified and to measure the effect of steam content (8-45%) on sorption. In addition, it is not known what level of sulfur removal is sufficient so that the downstream catalyst operation would not be impacted. Therefore, in this study experiments where the sorbent is placed upstream of a reforming catalyst bed are conducted to determine whether the sorbent can function effectively as a “guard bed” for downstream catalyst systems. 2. Experimental Section 2.1. Material Synthesis and Properties Determination. The manganese sorbent was prepared using incipient wetness impregnation of a fluidizable support developed at the National Renewable Energy Laboratory that is >90% alumina, 5.2% SiO2, and 2.5% MgO. The preparation method of the sorbent was adapted from Bakker et al.24 The sorbent was prepared by dropwise addition of a 2 M manganese acetate aqueous solution to the support. The aqueous solution was prepared with a manganese(II) acetate tetrahydrate (CH3COO)2Mn 3 4H2O salt (g99%, Aldrich catalog number 221007). The prepared sorbent was dried at 80 °C for 5 h in air then calcined at 600 °C for 6 h in air, with the ramp rate from room temperature to 80 and 80 °C to 600 °C being 10 and 5 °C/min, respectively. This impregnation-calcination procedure was repeated three times. The sorbent was analyzed for its manganese content using inductively coupled plasma-optical emission spectrometry (ICPOES). For the analysis, the sample was microwave digested in nitric acid, the solutions were then transferred to Nalgene volumetric flasks, brought to volume with deionized water, and analyzed by ICP-OES. The percent manganese on this sorbent was determined to be 8.3% by weight. After sulfidation experiments, the total sulfur content of the sorbent was measured with a LECO TruSpec Sulfur Add-On Module rated for sulfur measurements in the 0.001-20 wt % range. A fixed weight of the sample was mixed with 0.5-1.0 g of a combustion catalyst (LECO COM-CAT, part no. 502-321) and then combusted in a furnace at 1350 °C in an atmosphere of 99.5% oxygen. In the high temperature combustive environment, the sulfur-bearing compounds broke down and the sulfur content was oxidized to form SO2. The SO2 containing gas flowed through a magnesium perchlorate (Anhydrone) filter to remove moisture and a separate particulate filter. The gas then entered an infrared cell so that its absorption and a quantitative determination of the sulfur content can be made. For sorbent samples with high sulfur content, the calibration was performed using a sulfur in coal reference standard containing 1.45 ( 0.04% sulfur (LECO part no. 502-436). For sorbent samples with low sulfur content, the calibration was performed using a 0.0100% sulfur in white mineral oil certified reference material (IARM No. HP-13001A, LECO part no. 502-417). Blanks and calibration drifts are determined everyday prior to sample measurements.

(36) NETL. 2007 NETL Accomplishments; National Energy Technology Laboratory, U.S. Department of Energy, 2007; http://www.netl.doe.gov/ publications/others/accomp_rpt/accomp_fy07.pdf. (37) Siriwardane, R. V.; Woodruff, S. Ind. Eng. Chem. Res. 1995, 34 (2), 699–702. (38) Alonso, L.; Palacios, J. M. Energy Fuels 2002, 16 (6), 1550–1556. (39) Zhang, J.; Wang, Y.; Ma, R.; Wu, D. Fuel Process. Technol. 2003, 84 (1-3), 217–227. (40) Karayilan, D.; Dogu, T.; Yasyerli, S.; Dogu, G. Ind. Eng. Chem. Res. 2005, 44, 5221–5226.

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syngas, and up to 5 g of sorbent was used for the sulfidation experiments in syngas containing steam. The gas hourly space velocity (GHSV = volumegas/volumesorbent h) for experiments conducted with dry and wet syngas (45-68% steam) were 60 000 and 3 300 h-1, respectively. The overall composition of the gas used in the sorption experiments consists of simulated syngas, inert gas (nitrogen and/or helium), and water vapor (Table 1). For the 45% steam and dry experiments, the overall gas composition used was designed to maintain the same syngas content when steam levels were changed. In the dry experiments, additional nitrogen flow was used to equalize the space velocities in dry and wet conditions. However, for the 68% steam experiments, because the standard H2S cylinder in our laboratory was limited to approximately 2 000 ppmv (with an inert carrier), it was not possible to maintain both the same H2S concentrations and the same syngas ratio. A choice was made to equalize the H2S concentrations to the other experiments, and consequently the 68% steam experiments have lower syngas content. The regeneration experiments are conducted in 1-13 cycles. Six different regeneration conditions were examined (Table 2), and duplicate experiments for two of the conditions were performed. To determine the effectiveness of regeneration, sulfidation experiments were conducted immediately after regeneration and the second cycle breakthrough curves are examined. For combined sorbent/methane reforming tests, the MATS unit was operated in dual-bed mode (sorbent bed packed on top of catalyst). The syngas and H2S concentrations are designed to closely resemble those used for reforming catalyst research at NREL. Since the apparatus is only capable of a single temperature and space velocity at a time, the dual bed experiments were conducted at 750 °C in 60% (v/v) steam, at GHSV of 6 600 h-1 with respect to the sorbent. It should be noted that this temperature and gas composition is a compromise between the reforming catalyst and sorbent operation conditions; the reforming catalyst functions best at 850 °C and higher temperatures in syngas with high steam content, while sorbent performance in optimal at 700 °C or lower in dry syngas. Reforming tests were conducted using 0.22 g of a nickelmagnesium-potassium on alumina catalyst (overall composition 5.6 wt % Ni, 3.6 wt % Mg, 0.4 wt % K) with and without an upstream sorbent bed containing 4.0 g of fresh or regenerated manganese sorbent. The regenerated sorbent in the dual-bed study had undergone 10 short sulfidation-regeneration cycles (10 cycles of 10 min sulfidation-10 min regeneration). Regeneration was conducted with a steam-air mixture having a gas composition exactly the same as that in condition 6 in Table 2, though the regeneration was conducted at 750 °C. 2.3. X-ray Diffraction (XRD). X-ray diffraction was conducted to obtain structural information about the freshly synthesized and postreaction sorbent samples. Spectra were acquired using a Scintag spectrometer with a CuKR X-ray source and scanning a range of 20-100° 2θ with a step size of 0.03°. Powder diffraction files (PDFs) from the International Centre for Diffraction Data (ICDD) were used for diffraction assignments.

Figure 2. MATS reactor schematic.

2.2. Sorbent Performance Using a Microactivity Test System (MATS). The sorbents were tested in a microactivity test system as shown in Figure 2. The sorbent, supported on 0.2 g of quartz wool, was packed into quartz tube with 12 mm o.d. and approximately 9.6 mm i.d., which functions as a down flow packed bed reactor. Mass flow controllers (Celerity and Brooks) controlled gas flow rates and the reactant gas of desired composition was mixed in a gas manifold just prior to entering the quartz reactor tube. A BIOS Definer 220 primary flow meter with an uncertainty of 1% was used to calibrate the mass flow controllers used in the system. Water was pumped into to the system via an Instech P720 peristaltic pump, and a fine mist of the water was produced via a Sono-Tek ultrasonic atomizing nozzle system located at the top of the quartz reactor tube. Since the nozzle system is directly above the quartz reactor tube, it is heated to a certain extent, though it does not reach as high a temperature as the sorbent bed. The ultrasonic atomizing nozzle is capable of sonicating 0.3 mL/min and lower flow rates of water. The flow rate of the water was checked by bypassing the nozzle and collecting water in a graduated cylinder over a period of time. Dividing the volume collected over time yielded flow rate. In several repeat measurements, the average measured flow rates differed from the expected water flow rates by less than 1%. The reactor tube was heated by a furnace with temperature control provided by closed-loop feedback from an Omega K-type thermocouple in the bypass tube that was in approximately the same axial position as the sorbent bed. Reactant gases and steam exiting the reactor tube were cooled by water at 10 °C to remove water vapor and condensable materials. A Nafion membrane drier with nitrogen as a sweep gas was used downstream of the condenser to remove additional moisture from the exit gas stream. The exit gas was analyzed by a Varian CP4900 Micro-GC equipped with four columns for permanent gases, hydrocarbon, and H2S analyses. The sampling frequency was once per 4 min. Several types of experiments were conducted. For the sulfidation experiments, inlet H2S of 400 ppmv (total volume basis) was fed to the sorbent, and the outlet H2S as well as other gas components were measured as a function of time. First, to demonstrate its effectiveness in simulated syngas containing high steam content, the Mn sorbent was tested at 700 °C in 68% steam using 417 ppmv H2S (in total volume basis, it is 1300 ppmv in dry basis). The H2S content of all the sulfidation experiments that were designed to test sorbent efficiency is high so that the effect of the sorbent can be measured definitively and so that the experiment time is not excessively long. Typically, 0.5 g of sorbent was used for the sulfidation experiments in dry

3. Results 3.1. Thermodynamic Modeling and the Selection of Regeneration Conditions for Testing. We used sulfur sorbent literature findings and HSC 6.1, a thermodynamic software package, to help choose appropriate sorbent regeneration conditions, i.e., we first selected CO2, O2, and steam, and the relevant HSC models were used to help evaluate approximate levels of these gases in each of the six conditions before they were eventually chosen (Table 2). The HSC software only modeled bulk thermodynamics, not surface adsorption, and the calculations are used only to guide and set limits of experimental conditions. An excess of regeneration gases 382

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Table 1. Gas Composition (Mixture of Simulated Syngas, Inert Gas, and Water Vapor) for Sulfidation Reactions (68% Steam, 45% Steam, and Dry) and Methane Conversion Experimentsa species

68% steam

45% steam

dry

methane conversion experiments

H2S H2O inert (N2 or helium) CO H2 CH4 CO2 C2H4 benzene

417 ppmv 67.5% 19.8% 3.6% 3.5% 2.2% 2.9% 0.6% 129 ppmv

392 ppmv 45.0% 19.6% 10.1% 10.0% 6.1% 8.1% 1.6% 365 ppmv

392 ppmv

25.1 ppmv 59.4% 10.8% 5.6% 5.5% 3.4% 4.5% 0.9% 202 ppmv

a

64.2% 10.1% 10.0% 6.1% 8.1% 1.6% 365 ppmv

The concentrations of the gases are reported on a “total volume” basis.

Table 2. Regeneration Conditions Investigateda condition

inert (%)

1. low CO2 2. high CO2 3. low air 4. high air 5. steam 6. steam air

77.2 62.5 99.6 96.0 16.0

steam (%)

CO2 (%)

O2 (%)

22.8 37.5 0.4 4.0 100 80.0

4.0

All the regeneration cycles were conducted at 700 °C for the same amount of time as sulfidation. The low air, high air, and steam air conditions were obtained by mixing “zero air” (air with no CO2) with nitrogen or steam. a

Figure 3. Sulfidation and regeneration protocol used in this research.

was used in the modeling. The criterion was that the manganese speciation in the regeneration gas will have less than 0.03% MnSO4 according to thermodynamics.41 On the basis of the models, even in the highest CO2 level we used, the oxygen content generated from dissociation of CO2 at 700 °C would be less than 10-16 % of the gas composition. Therefore conditions 1 and 2 in Table 2 have very low “equivalent” oxygen levels, while condition 3 (“low air”) has intermediate oxygen level (0.4% oxygen), and conditions 4 and 6 (“high air” and “steam air”) have relatively high oxygen levels (4% oxygen). The thermodynamic calculation also predicted if regeneration gases were not in excess, sulfate formation is hard to avoid until higher temperature such as >900 °C and that the 4% oxygen condition was most likely to cause sulfate formation. 3.2. Sorbent Activity and Regeneration Testing. A series of experiments was conducted to determine the exit H2S level at the reactor outlet (in this case, MATS) as measured by gas chromatography as a function of time during the sulfidation stage. During the first 30 min of the experiment, the sorbent was in equilibration with a steam-containing inert gas or just inert gas for wet and dry sulfidation, respectively. Hydrogen sulfide was then introduced after 30 min time-on-stream. Figure 3 shows the temperature profile of the sulfidation and regeneration cycles. A sorbent that is efficient in removing H2S will result in H2S levels substantially lower than the input levels. Because of the overall length of the gas line, there is a delay in the breakthrough of all gases from the time when inlet gas started flowing, i.e., breakthrough does not immediately start when sulfur is introduced into the system. A sorbent that is efficient in H2S removal must be able to show a reduction in H2S level for a period longer than the breakthrough of other gases (preferably an inert tracer) in the same sulfidation experiment and for a period longer than the breakthrough of H2S in separate, blank experiments.

Figure 4. Duplicate experiments to determine the regenerability of the manganese sorbent after sulfidation in dry syngas. The error bars represent the estimated error based on the GC sampling time. Detailed gas composition is found in Table 1. The solid/filled circle and empty/unfilled triangles are from two different runs; the empty triangle run lasted 8 cycles, while the solid circle run lasted 13 cycles.

We measured the regeneration after sulfidation both in dry and wet syngas. In dry syngas, at 700 °C, the sorbent is significantly more effective than in wet syngas, with higher capacity and maintained the H2S at a low level for much longer.42 As a measure of the regeneration effectiveness, we determine the length of time in which the sorbent is able to keep the exit H2S below 20 ppmv in successive cycles in duplicate experiments (Figure 4). Since each cycle is 2 h long, the sorbent retains approximately 60% of its activity after 26 h of sulfidation (or 13 cycles of sulfidation-regeneration as shown in the solid circle run of Figure 4). The bulk of the other sulfidation and regeneration experiments are conducted in the 68% steam environment. Results of sulfidation in 45% steam are similar to those in 68% steam and are thus not shown. Figure 5 shows first cycle (42) Cheah, S.; Magrini-Bair, K. Produce and assess the performance of modified sulfur sorbents in high temperature high steam reforming conditions; National Renewable Energy Laboratory: Golden, CO, September 30 2009; http://devafdc.nrel.gov/bcfcdoc/10576.pdf.

(41) Turkdogan, E. T. Ironmaking Steelmaking 1993, 20 (6), 469–475.

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Figure 5. First cycle exit H2S (filled/solid symbols) and nonreactive gases (empty symbols) in simulated syngas containing 68% steam with fresh manganese sorbent in place. Symbols of the same shape are data collected in the same run, e.g., solid and empty triangles represent H2S and nonreactive gas measurements in the same experiment. In all experiments, there is a clear separation between H2S and the nonreactive gases. These data show seven replicates obtained under the same conditions. The different traces give an indication of the experimental uncertainties. Reaction conditions were inlet H2S 417 ppmv, 700 °C, and GHSV of 3 300 h-1.

Figure 7. Second cycle exit H2S (solid symbols) and nonreactive gases (empty symbols) in simulated syngas containing 68% steam with manganese sorbent that was regenerated partially. The H2S breakthrough curves for these regeneration conditions are much faster than those in Figure 5, indicating incomplete regeneration. Symbols of the same shape are data collected in the same run. Sulfidation conditions were the same as those in Figure 5.

“steam air” regeneration methods are the most effective (appear as squares, diamonds, and triangles, respectively, in Figure 6). Duplicate experiments of the “steam air” regeneration were conducted and the results are reproducible. As far as possible, the H2S breakthrough curves are referenced to the breakthrough curves of inert gases. However, for the “steam air” experiments, inert nitrogen was present in the regeneration cycle just prior to the second H2S sulfidation step and it was not possible to obtain breakthrough curves for inert gases. For those two experiments, methane breakthrough curves were used for comparison. This choice was justified since methane breakthrough curves were practically identical to those of inert gases in other experiments. Figure 7 shows second cycle H2S breakthrough curves after regeneration using the “steam,” “low CO2,” and “high CO2” conditions (appear as triangles, squares, and circles, respectively, in Figure 7). The breakthroughs occur much earlier than those in the first cycle (Figure 5), i.e., the regeneration conditions used produce sorbents that have approximately half of the capacity of fresh sorbents. The results indicate that the regeneration conditions in Figure 7 are not as effective as the regeneration conditions shown in Figure 6. Besides H2S, the other components of the syngas were also measured by gas chromatography, and the results were analyzed to determine whether there are other catalytic and sorption activities of the sorbent. This exercise is also important in our latter experiments to determine whether the sorbent is effective in protecting the downstream catalyst from the poisoning effect of H2S. Analysis of the concentrations (percentage) of CO and CO2 indicates that there is an early slight increase in CO2 and slight decrease in CO concentrations (Figure 8). This may be because the manganese sorbent also has some water gas shift activities. The concentration of CO2 decreases as exit H2S increases, suggesting the water gas shift catalytic sites lose their activities as they are occupied by H2S. Analysis of the number of moles of CO, CO2, CH4, H2, C2H4, and benzene in the 68% and 45% steam experiments was also conducted. This analysis was conducted first by calculating the volume of the exit gas using the actual normalized gas chromatographic measurement of the inert gas (helium or nitrogen in our gas stream), then calculating the number of moles of each gas by multiplying their concentrations by the volume of the exit gas. The analysis

Figure 6. Second cycle exit H2S (solid symbols) and nonreactive gases (empty symbols) in simulated syngas containing 68% steam with regenerated manganese sorbents. The separation between the H2S and inert breakthrough curves are comparable to those of fresh sorbents, which are shown in Figure 5. Consequently the regeneration protocols are considered successful. Symbols of the same shape are data collected in the same run. Sulfidation conditions were the same as those in Figure 5.

breakthrough curves of fresh sorbent with 417 ppmv H2S in syngas containing 68% steam. The sorbents were able to delay H2S breakthrough relative to those of nonreactive gases by approximately 20 min. As far as possible, the nonreactive gases used for comparison are inert gases (nitrogen or helium). After sulfidation experiments, the sorbents were analyzed for their total sulfur content using a LECO TruSpec Add-On Sulfur module as described in the Experimental Section. It was found that for sorbents that had undergone sulfidation in dry syngas, close to 90% of the manganese on the sorbent is utilized. For sorbent that had undergone sulfidation in steam, only approximately 0.1% of the manganese is utilized. This suggests a very small set of reactive species adsorb sulfur in high temperature, high steam conditions. The breakthrough curves in Figures 6 and 7 are second cycle H2S breakthrough curves in syngas containing 68% steam, i.e., breakthrough curves after the first sulfidation (in wet syngas) and regeneration cycle. The H2S breakthrough curves are compared to those of nonreactive gases. For regeneration conditions that are effective, the sorbents should retain their capacity in the second cycle, i.e., having H2S breakthroughs similar to those of the fresh sorbents (Figure 5). It was found that the “low air,” “high air,” and 384

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(approximately 18% more). In the blank experiment (using the alumina support in place of the sorbent), there is no increase of hydrogen production. The analysis also indicates that there is slightly less methane and ethane in the exit stream, with approximately 10% of the methane and 20% of the ethane converted to other gas components or char. The exit gas does contain C2H2, potentially from the dehydrogenation reaction of ethane or dimerization of dehydrogenated methane, as described below: 2CH4 T C2 H2 þ 3H2 Figure 8. Concentrations of CO and CO2 (in %) and H2S (in ppmv) as a function of time during second and third cycle sulfidation (in syngas with 68% steam) and regeneration. Temperature was 700 °C. Sulfidation is from 150 to 210 min, though the GC results have approximately a 10 min delay. Regeneration is from 210 to 270 min. At time = 270 min, the third cycle sulfidation starts.

ðReaction 2Þ

though the reaction is still not very thermodynamically favorable at 700 °C. Decrease of hydrocarbons was also measured for the experiments conducted with alumina support, rather than sorbent in place. The result suggests that the slight decrease in hydrocarbons could be due to coke formation or hydrocarbon reforming reaction that can occur in the gas phase or catalyzed by solid surfaces. The reactions involving methane are shown below to help illustrate the general hydrocarbon reforming reaction. Both steam and carbon dioxide can participate in methane reforming reactions. H2 O þ CH4 T CO þ 3H2

ðReaction 3Þ

CO2 þ CH4 T 2CO þ 2H2

ðReaction 4Þ

The solid surfaces that can have catalytic activity include the manganese oxide sorbent or the small amount of trace metals in the support (the support contains 0.0022% MnO2 and 0.16% Fe2O3, both of which can be catalytically active. The support contains no nickel). The carbon mass balance in dry syngas containing H2S is 95% (1st cycle). The carbon mass balance in syngas containing 45 or 68% steam is 93-98% in the first cycle and 86-98% in subsequent cycles (for regeneration experiments that contain up to 10 sulfidation cycles). Though these values compare well to the carbon mass balance of 94-97% in the blank experiments, which were conducted with the gas stream heated to 700 °C without sorbent in place, they do not completely preclude the formation of a small amount of coke. In summary, analysis of the data of gases other than H2S indicates that the sorbent has water gas shift catalytic activity. The water gas shift activity was not detectable in blank tube experiments. There is a small loss/conversion of hydrocarbon to either coke or other carbon containing gases such as C2H2. The hydrocarbon conversion is approximately the same magnitude for experiments conducted with manganese sorbent or with the alumina support only. In addition to experiments with sorbents only, we also conducted experiments with nickel reforming catalyst downstream of the sorbent. In the experiments, inlet simulated syngas containing 11% methane on a dry basis (3.4% total volume basis) was flowed into the catalyst or dual bed to obtain steady state methane conversion prior to introduction of 25.1 ppmv H2S. The percent methane conversion is plotted as a function of time on stream. The catalyst used for the experiments is a nickel catalyst developed at NREL. Figure 10 shows the results from three sets of experiments: catalyst only, fresh sorbent on fresh catalyst, and regenerated sorbent on fresh catalyst. Without the upstream sorbent, the catalyst began losing methane reforming activity immediately upon addition of

Figure 9. Number of moles of CO, CO2, (Figure 9a) CH4, and H2 (Figure 9b) in the inlet and outlet streams. Conditions of the experiments are the same as those in Figure 8. Note that the number of moles of CO2 and H2 exiting the reactor are much higher than the number of moles of these gases in the inlet stream, while the number of moles of CO exiting is lower than the number of moles in the inlet stream.

indicates that in the presence of the sorbent, there is fewer and more number of moles of CO and CO2, respectively, in the exit stream than in the inlet stream (Figure 9a). This result is in agreement with the interpretation of water gas shift reaction through analysis of the gas concentrations. The stoichiometry of the water gas shift reaction would also predict a larger number of moles of H2 in the exit stream (CO þ H2O = H2 þ CO2), which is also verified in the analysis (Figure 9b). However, the number of moles of H2 in the exit stream of the 45% steam experiment is only slightly more than the number of moles of H2 in the inlet stream (approximately 4% more) while the number of moles of H2 produced in the 68% steam experiment is higher 385

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Figure 10. Methane conversion for three sets of experiments: (1) catalyst unprotected by sorbent, (2) catalyst protected by upstream fresh sorbent, and (3) catalyst protected by upstream regenerated sorbent. The catalyst only experiments are labeled “cat only rep1” and “cat only rep2 incomplete reduction. The other labels are selfexplanatory. The detailed inlet gas composition is described in Table 1. Reaction conditions: temperature 750 °C, GHSV with respect to the sorbent 6 600 h-1.

Figure 11. X-ray diffraction spectra of manganese sorbents pre- and postreaction. The black lines labeled (a) to (c) are experimental spectra. The vertical gray and colored straight lines indicate the diffraction angles (2θ) from published, well characterized solids in the database of the International Centre for Diffraction Data (ICDD).

Mn2O3 (PDF no. 894836). Additional peaks attributed to Mn3O4 (PDF no. 894837) were observed at 2θ of 28.9° and 32.4°. This indicates the oxidation states of manganese supported on the alumina used are a mixture of 2þ and 3þ. After sulfidation in dry syngas, the aluminum oxide peaks remain in the XRD spectrum of the postreaction manganese on aluminum oxide sorbent (trace b of Figure 11), but the Mn2O3 and Mn3O4 peaks have completely disappeared, with new peaks appearing in the 34.3° and 49.3° positions, which are from manganese sulfide, MnS (PDF no. 894952). For sulfidation in steam, XRD showed that manganese in the sorbent sample was converted to MnO (trace c of Figure 11). No crystalline sulfur-containing phase was detected.

H2S to the gas stream (t = 90, Figure 10). In one of the replicates of the catalyst only experiments, the hydrogen reduction program for the catalyst (where the catalyst was normally reduced by hydrogen prior to reaction with syngas) was not turned on and the catalyst was only reduced in situ by the syngas itself (empty squares). Consequently the methane conversion efficiency of this experiment was less than that of the other. Nevertheless, the deactivation of this “incompletely reduced” catalyst follows the same trend as the completely reduced catalyst. With the addition of the sorbent bed upstream, catalyst activity was improved and the reforming activity remained unchanged operating at 80% methane conversion for more than 20 min (“fresh sorbent on cat” in Figure 10). With the use of regenerated sorbent, the methane conversion activity also remained unchanged for more than 20 min (“regenerated sorbent on cat rep 1” and “regenerated sorbent on cat rep2” in Figure 10). The methane conversions for the duplicate regenerated sorbent experiments do not completely overlay each other. However, within experimental uncertainty, both experiments showed that the regenerated sorbents were just as effective as the fresh sorbent in prolonging the life of the catalyst. Our earlier analysis of the sorbent only data (Figure 9) show that the methane “loss” or “conversion” in sorbent was only about 10%. When calculated in number of moles converted per gram of catalyst/material, the methane conversion rate measured in Figure 9 is much smaller than those in Figure 10. Consequently, the increase in time for effective methane conversion when a sorbent is upstream of the catalyst (Figure 10) is not due to any potential reforming activity of the sorbent. Rather, the increase in time of catalyst effectiveness is most likely due to removal of H2S from the syngas by the sorbent. During the time frame, the sorbent was able to remove H2S and the nickel methane reforming catalyst functions without any deterioration in activity. 3.3. X-ray Diffraction Results. The X-ray diffraction (XRD) results are shown in Figure 11. Analysis of the manganese on alumina sorbent (trace a in Figure 11) indicates that the X-ray diffraction spectrum is best fitted with R-Al2O3 (PDF no. 461212), which form the dominant peaks at 2θ of 25.7°, 35.2°, 43.5°, 52.7°, and 57.6°. The other dominant peaks at 33.1 and 55.3 are associated with

4. Discussion We have demonstrated that the manganese on alumina sorbent was able to achieve close to 100% H2S removal for syngas containing no steam or 45-68% steam at 700 °C (see Figure 5). In addition to sulfur sorption, the sorbent has some water gas shift activities as well. This material comprises a new class of sulfur sorbent that effectively removes H2S in the presence of steam and at temperatures >700 °C. In addition, this project investigated several regeneration conditions for the alumina supported manganese sorbent that has been sulfided in dry and wet syngas. It was found that regeneration conditions with oxygen (can be obtained through a mixture of air and nitrogen) or steam in combination with oxygen is the most effective. These regeneration gases are relatively inexpensive compared to the use of hydrogen, which is required for catalyst regeneration. Detailed studies of the surface species formed during regeneration of manganese sorbent with steam and oxygen are in progress in this laboratory. Siriwardane et al.37,43 and Sasaoka et al.44 have conducted detailed studies of the interaction of ZnS with O2 and/or H2O during regeneration and some of the surface species found may be translational to other oxides, though the details would be different. For example, Siriwardane and Woodruff found that in low partial (43) Siriwardane, R. V.; Woodruff, S. Ind. Eng. Chem. Res. 1997, 36 (12), 5277–5281. (44) Sasaoka, E.; Hatori, M.; Sada, N.; Uddin, A. Ind. Eng. Chem. Res. 2000, 39 (10), 3844–3848.

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pressure of oxygen (