Gasification Process Selection- Trade-offs and Ironies

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1 Gasification Process Selection- Trade-offs and Ironies Neville Holt EPRI Presented at the Gasification Technologies Conference 2004 October 3-6, 2004 JW Marriott Hotel, Washington, DC Introduction The best gasification technology for a given application will depend on the project objectives and the range of coal or other feedstocks to be used. The range of objectives includes: Hydrogen Methanol or Dimethyl Ether (DME) Ammonia Fischer Tropsch (F-T) Liquids Power only without CO 2 capture Power only with CO 2 Capture Power and co-production of Hydrogen, F-T etc. Lowest Cost of Electricity (COE) Lowest COE but meeting Efficiency goals (e.g. Draft Energy Bill) If the application is for hydrogen production or for synthesis of ammonia, methanol or Fischer Tropsch liquids the preferred syngas would comprise mostly carbon monoxide and hydrogen. If methane is present in the syngas it does not participate in the shift and subsequent synthesis reactions and represents a lower yield of product and an extra, essentially inert, volume load that is an economic detriment. This is particularly the case where the synthesis reaction is conducted in a recycle loop to increase the conversion of CO + H 2 and where inerts such as methane or nitrogen would build up to unacceptable levels. If the application is IGCC for power only without CO 2 capture the presence of methane is certainly acceptable and may lead to a higher efficiency and lower oxygen consumption. However, if the objective was for power only but for maximum CO 2 capture then the presence of methane in the syngas reduces the amount of coal carbon that can be captured by the shift plus CO 2 capture route. Generally, gasification at a higher pressure is advantageous for CO 2 capture since a physical absorption system such as Selexol can be used. With physical absorption, much of the CO 2 can be recovered by pressure reduction at small energy penalty, however with a chemical absorption such as MDEA the absorbed CO 2 must be removed mostly by steam stripping of the rich solvent at much higher energy penalty. However, if the 1

2 gasification process produces methane the yield of methane increases with pressure so that the amount of coal carbon available for capture is less. Gasification Chemistry and Reactions The following reactions are important in coal gasification: Coal Devolatilization = CH 4 + CO + CO 2 + Oils + Tars + C (Char) C + O 2 = CO 2 ((exothermic rapid) C + 1/2O 2 = CO (exothermic rapid) C + H 2 O = CO + H 2 (endothermic slower than oxidation) C + CO 2 = 2CO (endothermic slower than oxidation) CO + H 2 O = CO 2 + H 2 Shift Reaction(slightly exothermic rapid) CO + 3H 2 = CH 4 + H 2 O Methanation (exothermic) C + 2H 2 = CH 4 Direct Methanation (exothermic) The first six of these reactions are the most important in the entrained gasification processes used in the current IGCC plants. Methane formation is more evident in lower temperature systems. High pressures and lower temperatures favor the methanation reactions. However, in most cases the methane content is higher than would be predicted by equilibrium because methane is also formed during the primary devolatilization of the coal (this methane has sometimes been called prompt methane). Under the reducing conditions of gasification, the sulfur in the coal is converted primarily to hydrogen sulfide, H 2 S, with ~3-10% of the sulfur converting to carbonyl sulfide, COS. This typically necessitates the use of a COS hydrolysis reactor to convert the COS to H 2 S prior to H 2 S removal by well known solvent absorption processes widely used in the gas processing and petroleum industries. Gasification conditions favor the conversion of fuel bound nitrogen to gaseous nitrogen and ammonia, NH 3. Higher temperatures favor the further destruction of ammonia to nitrogen and hydrogen so that the ammonia content of the raw syngas is primarily a function of the gasifier outlet temperature. Small amounts of HCN are also formed but may be removed in the COS hydrolysis reactor. Tars, oils, and phenols survive in the lower temperature outlets of moving bed gasifiers and these species contain some of the fuel s oxygen, nitrogen, and sulfur as more complex molecules. Gasification Processes Three major types of gasification are used today moving bed, fluidized bed, and entrained flow. These processes are illustrated in Figure 1. Pressurized gasification is preferred for IGCC to avoid large auxiliary power losses for compression of the syngas up to gas turbine inlet pressure. Most gasification processes currently in use or planned for IGCC applications are oxygen blown. 2

3 Since synthesis reactions and economics are generally improved by higher pressure pressurized gasification is also favored for the synthesis application. Figure 1 The Three Major Types of Gasification Processes As mentioned above some methane is produced is produced by decomposition of the coals volatile matter. Some coals may also have methane surface absorbed within the pores. The survival of this methane in the final product gas depends on the temperature and kinetics. At lower gasifier outlet temperatures more of this methane survives. Since both moving bed gasifiers (e.g. Lurgi, BGL) and fluid bed gasifiers (HT Winkler, KBR Transport, GTI U Gas) have lower outlet temperatures (below the ash slagging 3

4 temperatures) than the single stage entrained gasifiers (Texaco, Shell, GSP/NOELL) the syngas from these gasifiers is of much higher methane content, representing typically 10-15% of the coal s carbon content at Barg ( psig). It must also be noted that because of their operating temperature fluid bed gasifiers also have lower carbon conversion and their ash contains more carbon that the slag from other slagging gasifiers. The production of methane from the methanation reactions shown above is favored by higher pressure. Some data on the effect of pressure can be seen in Table 1 which shows the syngas compositions from several moving bed and fluid bed gasifiers. Table 1 Syngas Compositions from Fluid and Moving Bed Gasifiers (mol % Clean Dry Basis Typical Bituminous coal) Gasifier Type Pressure Barg (Psig) Moving Dry Ash Moving Slagging Moving Slagging Fluid KRW Fluid KBR Transport Fluid Synthane 27.5 (400) 27.5 (40) 69(1000) 31(450) 31 (450) 69 (1000) H CO CH CO N 2 + A In single stage entrained flow gasifiers the fine coal particles react with the concurrently flowing steam and oxygen. Residence time is very short (a few seconds) and the operating temperature is above the ash fusion temperature to ensure destruction of tars and oils and to achieve high carbon conversion. The methane content is very low but it can be monitored as an indication of gasifier temperature. Entrained gasifiers have relatively high oxygen requirements and the raw gas is of high sensible heat content. The various designs of entrained flow gasifiers differ in their feed systems (dry pneumatic or coal/water slurries), vessel containment for the hot conditions (refractory or water wall), and configurations for recovery of the sensible heat from the raw gas. Some gasifier designs use two stages to improve gasifier cold gas efficiency and to reduce the sensible heat in the raw gas and to lower the oxygen requirements. In a two stage entrained gasifier, the coal fed to the second stage reduces the outlet temperature and there is some methane survival in the syngas. The methane content will increase if a higher proportion of the coal is fed to the second stage. The typical syngas compositions from several entrained gasification processes are shown in Table 2. 4

5 Table 2 Syngas Compositions from Entrained Coal Gasification Processes (Mol% Clean Dry Basis Typical Bituminous Coal) Gasifier Stages / Feed Pressure Barg (Psig) Single / Slurry Single / Dry Two / Slurry Two/Slurry with More Feed to 2 nd stage Two / Dry 69 (1000) 34 (500) 31(450) 31(450) 69(1000) H CO CH 4 <0.1 < CO N 2 + A Entrained-flow gasifiers have been selected for the majority of commercial sized IGCC project applications. These include the coal/water-slurry-fed processes of Texaco (Cool Water, and Tampa, US) and E-Gas (ConocoPhillips formerly Global, Destec, Dow Dow, Plaquemine, and Wabash plant, USA) and the dry-coal-fed processes of Shell (Buggenum, Netherlands), Prenflo Krupp-Uhde (Puertollano, Spain), GSP (Schwarze Pumpe, Germany), and Mitsubishi (Nakoso, Japan). The Mitsubishi and E-Gas processes employ two stages of gasification. The atmospheric pressure Koppers-Totzek process was developed in the 1950s, and commercial units operated in Greece, Turkey, India, South Africa, Zambia, and elsewhere, mostly for ammonia manufacture. A major advantage of the high-temperature entrained-flow gasifiers is that they avoid tar formation and its attendant problems. Their syngas has little methane and is very suitable for hydrogen and synthesis gas products. The high reaction rate also allows single gasifiers to be built with large gas outputs sufficient to fuel the large commercial gas turbines now entering the marketplace. The IGCC projects based on petroleum residuals all use entrained downflow refractory lined gasifiers from either Texaco or Shell. There are also over a hundred of these gasifiers in operation worldwide for the manufacture of ammonia, methanol, hydrogen and other chemicals. Methane Formation in Gasifiers Trade-offs and Ironies Methane in the syngas correlates with higher cold gas efficiency and lower oxygen usage. In an IGCC, higher cold gas efficiency means that more of the coal s energy (as syngas) can be used in the more efficient Brayton gas turbine cycle rather than as sensible heat into the less efficient Rankine steam cycle. However, methane in the syngas reduces the percentage of the coal s carbon that can be captured via the Shift reaction and subsequent CO 2 removal. There are some limits, both economic and thermodynamic, with regard to how far to take the shift reaction. Most of the CO conversion (80-85%) can be achieved by high temperature shift. Additional CO conversion can be obtained in subsequent low temperature shift reactors at increasing energy penalties for each mole of CO converted. 5

6 Increased pressure further increases methane production and gasifier efficiency and further reduces oxygen usage. Increased pressure for methane producing gasifiers therefore also further reduces the percentage of the coal s carbon that can be captured. However, gasification at a higher pressure is economically advantageous for CO 2 capture since a physical absorption system such as Selexol can be used. With Selexol physical absorption, much of the CO 2 can be recovered by pressure reduction to 3-4 barg pressure (50 psig) with considerable savings in CO 2 compression costs, auxiliary power usage and steam consumption. On the other hand, with a chemical absorption system such as those based on MDEA (MethyDiethanolamine), the absorbed CO 2 must be removed mostly by steam stripping of the rich solvent at much higher energy penalty. Gasifier Selection for IGCC without CO 2 Capture In the absence of any requirement or regulation for CO 2 capture, the selection for IGCC is more open to all types of gasifier and would be evaluated presumably based on the traditional criteria of COE and perception of risk and availability. Methane in the syngas is an enhancement to the syngas heating value. In this respect, the methane producing gasifiers, such as fluid and moving beds and two stage entrained systems, with higher cold gas efficiencies may show some advantage. However, each technology must be evaluated on its total characteristics rather than efficiency alone. The choice will also be markedly affected by coal type and low rank coals may show better performance in fluid bed gasifiers than in entrained systems at their current stage of development. Gasifier Selection for Hydrogen, Maximum CO 2 Capture and Synthesis If the overall project goal is >90% capture of the coal s carbon and production of Hydrogen (e.g. the currently stated FutureGen project goals), then a single stage entrained gasifier at high pressure (69 barg (1000 psig)) operating with water Quench is the preferred technology. Single stage entrained gasifiers operate at high temperatures ( C) so that very little methane is produced. Nearly all the coal s carbon is in the syngas as CO and CO 2 and is amenable to capture through the shift and CO 2 removal process steps. The quench mode is the least cost method of putting the moisture in the raw syngas needed for the Shift reaction. Other configurations would add expensive syngas coolers for steam production and/or rob the steam cycle. These aspects are further illustrated in the economic evaluations of the competing gasification technologies with and without CO 2 capture shown in Table 3. These estimates for currently commercially available Texaco, E Gas and Shell IGCC s using bituminous coals show a significant COE advantage over PC plants when capture is required. There is also a particular advantage to high-pressure gasification operation. For the current lower pressure (31-36 Barg ( psig)) E Gas and Shell IGCC s there is a lower advantage over PC plants with amine scrubbing than with the higher pressure Texaco Quench IGCC. 6

7 If the application is for hydrogen production or for synthesis of ammonia, methanol or Fischer Tropsch liquids, the preferred syngas should comprise mostly carbon monoxide and hydrogen. If methane is present in the syngas, it does not participate in the shift and subsequent synthesis reactions and represents a lower yield of product and an extra, essentially inert, volume load that is an economic detriment. This is particularly the case where the synthesis reaction is conducted in a recycle loop to increase the overall conversion of CO + H 2 and where inerts such as methane or nitrogen would build up to unacceptable levels. Table 3 COE and Avoided Cost of CO 2 for IGCC and PC Plants with Capture - Bituminous Coals Technology (# Gasifiers) Without Capture Texaco Q (2+1) Texaco R (2+1) E Gas (2+0/2+1) Shell (2+0/2+1) PC Ultra Supercritical Net MW Heat Rate Btu/kWh TPC $/kw / / COE $/MWh / / CO2 Emissions mt/mwh With Capture Net Heat Rate Btu/kWh 11,300 10,700 11,000 10,400 11,300 TPC $/kw / / Fixed O&M $/MWh / / Variable O&M $/MWh / / Fuel $/MWh (Coal $1.422/GJ/$1.50/MBtu) Capital Charge $/MWh / / COE $/MWh / / COE Ratio (With/without Capture) / / CO 2 Emissions mt/mwh CO 2 Captured mt/mwh Avoided Cost $/mt of / / CO 2 7

8 Entrained Gasifier Improvements Each of the major entrained coal gasification technologies have several candidate improvements that could be potentially be demonstrated at FuturGen consistent with the currently stated goals. Slurry fed gasifiers (Texaco, E Gas) have the advantage of being able to pump the feed to high pressures. The energy used in pumping is very much less than the energy used in conveying gas compression. Some schemes have been suggested to use slurry pumping to attain high pressures and with additional flash drying to give a dry coal feed with the flashed steam added back to the syngas downstream of the gasifier to provide the syngas moisture for the shift reaction. Another alternative is to feed the coal as a coal in liquid CO 2 slurry either with or without a flash step. Such improvements could be particularly advantageous for the abundant, and low cost, low rank coals such as Powder River Basin (PRB) sub-bituminous coals. Some improvements more specifically related to the Texaco process are improved carbon conversion per pass (possibly in conjunction with a new improved feed system) and a continuous slag let down system to eliminate the lock hoppers. The replacement of the carbon scrubber by a warm or hot gas filter could markedly reduce O&M costs associated with the black and gray water circuits around the scrubber and to improve plant availability. Use of a cooled screen instead of a refractory lining for the gasifier could also reduce forced outages and improve availability. A higher pressure E Gas gasifier of a tall cylindrical design (perhaps with two diameters) has been suggested. If demonstrated this would probably avoid the size constraint imposed by the current inverted T (sometimes called the iron cross) design for low rank coals and could enable lower cost CO 2 capture through use of a physical absorption system such as Selexol. Although there is methane production from the second stage feed, the two stage gasifiers could be run with only minor coal slurry fed to the second stage and with additional water as quench to achieve the lower outlet temperature and to produce a syngas of low methane consistent with the needs for hydrogen, high CO 2 capture and for synthesis applications. Operating in this manner could also eliminate the need for a syngas cooler. E Gas already incorporates a continuous slag removal process and a hot gas filter in their process. The IEA GHG R&D sponsored study with Foster Wheeler Italiana showed that dry coal fed entrained gasifiers such as Shell and GSP/NOELL become more expensive and less efficient as long as they stay with the lock hopper pneumatic conveying feed systems. Higher pressures mean more conveying nitrogen per unit of coal fed. A truly continuous high pressure coal feeder, preferably on as-received coal or minimally dried coal, would be a marked improvement. Perhaps these organizations could use their dry coal feed expertise to adopt something like a pumped slurry flash system as feed at high pressure. Shell currently uses an expensive syngas cooler in their solid fuel gasification process, however for hydrogen production and synthesis they could adopt a lower cost quench system. The Shell process already incorporates a cooling screen (water wall) and a hot gas filter but would benefit from a continuous slag removal system. 8

9 Is 90% CO 2 Capture Really Necessary? Although it is a desirable goal, perhaps given some of the inherent limitations of the technology described above, it may not be necessary to achieve 90% capture in many situations and perhaps this particular FutureGen goal could be modified. If 70-80% capture was acceptable then the choice of gasifiers could extend beyond the single stage entrained quench gasifiers to include the fluid bed and two stage entrained gasifiers with their higher gasifier efficiencies. Advanced Concept Power Blocks These observations on CO 2 capture limitations via the Shift/CO 2 removal route apply to IGCC configurations with a gas turbine combined cycle power block. Some advanced concepts have been suggested that could potentially capture CO 2 from the power block exhaust flue gas. For such concepts there would be no limit on the acceptable fuel components (e.g. methane) in the syngas. The oxygen fired rocket engine proposed by Clean Energy Systems could be fired with clean syngas of any composition and after condensing the moisture would result in a concentrated CO 2 exhaust stream that could be dried and compressed for transportation and sequestration. Siemens Westinghouse has been developing a Solid Oxide Fuel Cell (SOFC) that incorporates an oxidizing function (similar to the Oxygen Transfer Membranes (OTM) being developed by Air Products and Praxair under the DOE program) for completing the combustion of the anode gas to CO 2 and moisture. The SOFC could potentially be supplied with clean syngas of any composition (providing it was clean enough) and the resultant exhaust stream could be dried and compressed for transportation and sequestration. A 250 kw SOFC with this OTM feature has been supplied by Siemens to Shell Hydrogen at a Norwegian location. Although such concepts could be tested at some scale on slip streams at a FutureGen facility it is rather unlikely that these technologies would have advanced enough to be considered for the prime power block in any FutureGen project initiated in the next five years. Gasifier Selection for Polygeneration or IGCC Co-Production If the requirement for capture could be relaxed then a wider range of gasifiers could be used in a polygeneration or co-production mode. The configuration could feature shift and CO 2 removal with hydrogen production from some of the syngas by Pressure Swing Absorption (PSA), and power generation in a power block firing Hydrogen and methane with the PSA filtrate returned as fuel to the power block either compressed and added to the main H 2 /CH 4 fuel gas or duct fired in the HRSG. If some synthesis of Methanol, DME or F-T liquids is required then a once-thru Liquid Phase LP synthesis reactor (e.g. Air Products design as used at Eastman) could be used and the methane would then pass through and be part of the syngas fuel to the power block. 9

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