188.8.131.52 Steam reforming of gas and light hydrocarbons Steam reforming is the dominant technology for hydrogen production today and the largest single train plants produce up to 480 tH2 d-1. The primary energy source is often natural gas, Then the process is referred to as steam methane reforming (SMR), but can also be other light hydrocarbons, such as naphtha. The process begins with the removal of sulphur compounds from the feed, since these are poisons to the current nickel-based catalyst and then steam is added. The reforming reaction (1), which is endothermic, takes place over a catalyst at high temperature (800°C-900°C). Heat is supplied to the reactor tubes by burning part of the fuel (secondary fuel). The reformed gas is cooled in a waste heat boiler which generates the steam needed for the reactions and passed into the CO shift system. Shift reactors in one or two stages are used to convert most of the CO in the syngas to CO2 (Reaction 3, which is exothermic).
The conventional two-stage CO conversion reduces the CO concentration in syngas (or in hydrogen) down to 0.2-0.3%. High temperature shift reactors operating between 400°C and 550°C and using an iron-chromium catalyst leave between 2% and 3% CO in the exit gas (dry basis). Copper-based catalyst can be used at temperatures from 180°C-350°C and leave from 0.2-1% CO in the exhaust. Lower CO content favours higher CO2 recovery. The gas is then cooled and hydrogen is produced by a CO2/H2 separation step. Until about 30 years ago, the CO2 was removed using a chemical (solvent) absorption process such as an amine or hot potassium carbonate and was rejected to atmosphere as a pure stream from the top of the regenerator. There are many of these plants still in use and the CO2 could be captured readily.
Modern plants, however, use a pressure swing adsorber (PSA), where gases other than H2 are adsorbed in a set of switching beds containing layers of solid adsorbent such as activated carbon, alumina and zeolites (see the fuller description of PSA in Section 184.108.40.206). The H2 exiting the PSA (typically about 2.2 MPa) can have a purity of up to 99.999%, depending on the market need. The CO2 is contained in a stream, from the regeneration cycle, which contains some methane and H2. The stream is used as fuel in the reformer where it is combusted in air and the CO2 ends up being vented to atmosphere in the reformer flue gas. Hence, to capture CO2 from modern SMR plants would require one of the post-combustion processes described above in Section 3.3. Alternatively, the PSA system could be designed not only for high recovery of pure H2 but also to recover pure CO2 and have a fuel gas as the third product stream.
In a design study for a large modern plant (total capacity 720 tH2 d-1), the overall efficiency of making 6.0 MPa H2 from natural gas with CO2 vented that is without CO2 capture, is estimated to be 76%, LHV basis, with emissions of 9.1 kg CO2/ kg H2 (IEA GHG, 1996). The process can be modified (at a cost) to provide a nearly pure CO2 co-product. One possibility is to remove most of the CO2 from the shifted, cooled syngas in a 'wet' CO2 removal plant with an appropriate amine solvent. In this case the CO2-deficient syngas exiting the amine scrubber is passed to a PSA unit from which relatively pure H2 is recovered and the PSA purge gases are burned along with additional natural gas to provide the needed reformer heat. The CO2 is recovered from the amine solvent by heating and pressurized for transport. Taking into account the power to compress the CO2 (to 11.2 MPa) reduces the efficiency to about 73% and the emission rate to 1.4 kgCO2/kgH2, while the CO2 removal rate is 8.0 kgCO2/kgH2. 2 2 2
220.127.116.11 Partial oxidation of gas and light hydrocarbons In the partial oxidation (POX) process (reaction 2), a fuel reacts with pure oxygen at high pressure. The process is exothermic and occurs at high temperatures (typically 1250°C-1400°C). All the heat required for the syngas reaction is supplied by the partial combustion of the fuel and no external heat is required. As with SMR, the syngas will be cooled, shifted and the
CO2 removed from the mixture. The comments made on the 18.104.22.168 Gasification of coal, petroleum residues, or biomass separation of CO2 from SMR syngas above apply equally to the POX process. POX is a technology in common use today, the efficiency is lower than SMR, but the range of fuels that can be processed is much wider.
For large-scale hydrogen production, the oxygen is supplied from a cryogenic air separation unit (ASU). The high investment and energy consumption of the ASU is compensated by the higher efficiency and lower cost of the gasification process and the absence of N2 (from the air) in the syngas, which reduces the separation costs considerably. However for pre-combustion de-carbonization applications, in which the hydrogen would be used as fuel in a gas turbine, it will be necessary to dilute the H2 with either N2 or steam to reduce flame temperature in the gas turbine combustor and to limit NO emission levels. In this case x the most efficient system will use air as the oxidant and produce a H2/N2 fuel mixture (Hufton et al. 2005)
22.214.171.124 Auto-thermal reforming of gas and light hydrocarbons
The autothermal reforming (ATR) process can be considered as a combination of the two processes described above. The heat required in the SMR reactor is generated by the partial oxidation reaction (2) using air or oxygen, but because steam is supplied to the reactor as well as excess natural gas, the endothermic reforming reaction (1) occurs in a catalytic section of the reactor downstream of the POX burner. The addition of steam enables a high conversion of fuel to hydrogen at a lower temperature. Operating temperatures of the autothermal process are typically 950-1050°C, although this depends on the design of the process. An advantage of the process, compared to SMR, is the lower investment cost for the reactor and the absence of any emissions of CO2 since all heat release is internal, although this is largely offset by investment and operating cost for the oxygen plant. The range of fuels that can be processed is similar to the SMR process, but the feed gas must be sulphur free. CO2 capture is accomplished as described above for the steam methane reforming.
Each of the three syngas generation technologies, SMR, ATR and POX produce high temperature gas which must be cooled, producing in each case a steam flow in excess of that required by the reforming and shift reactions. It is possible to reduce this excess production by, for example, using preheated air and a pre-reformer in an SMR plant. Another technique is to use the hot syngas, leaving the primary reactor, as the shell-side heating fluid in a tubular steam/hydrocarbon reforming reactor which can operate in series, or in parallel, with the primary reactor (Abbott et al., 2002). The addition of a secondary gas heated reformer will increase the hydrogen production by up to 33% and eliminate the excess steam production. The overall efficiency is improved and specific capital cost is typically reduced by 15%. Again, CO2 capture is accomplished as described previously for steam methane reforming.
Figure 3.14 Simplified schematic of a gasification process showing options with CO2 capture and electricity, hydrogen or chemical production.
Gasification (see Figure 3.14) is a chemical process aimed at making high-value products (chemicals, electricity, clean synthetic fuels) out of low-value solid feedstocks such as coal, oil refining residues, or biomass. Gasification is basically partial oxidation (reaction 2), although steam is also supplied to the reactor in most processes. Fixed bed, fluidized bed or entrained flow gasifiers can be used. These can have very different characteristics with respect to oxidant (air or O2), operating temperature (up to 1350oC), operating pressure (0.1-7 MPa), feed system (dry or water slurry), syngas cooling method (water quench or via radiative and convective heat exchangers) and gas clean-up system deployed. These alternative design options determine the fraction of feedstock converted to syngas, syngas composition and cost. As economics depend strongly on scale, gasification is generally considered to be suitable only for large plants. The gasifier output contains CO, H2, CO2 H2O and impurities (e.g., N2, COS, H2S, HCN, NH3, volatile trace minerals and Hg) that must be managed appropriately.
A worldwide survey of commercial gasification projects identified 128 operating gasification plants with 366 gasifiers producing 42,700 MWt of syngas (NETL-DOE, 2002 and Simbeck, 2001a). There are also about 24,500 MWt of syngas projects under development or construction, with 4000-5000 MWt of syngas added annually. The feedstocks are mainly higher rank coals and oil residues. Most commercial gasification growth for the last 20 years has involved entrained-flow gasifiers, for which there are three competing systems on the market. Recent commercial gasification development has been mainly with industrial ammonia production, industrial polygeneration (in which clean syngas is used to make electricity and steam along with premium syngas chemicals) and IGCC power plants. Commercial experience with biomass gasification and fluidized bed gasification has been limited.
CO2 capture technology is well established for gasification systems that make chemicals and synthetic fuels (NETL-DOE, 2002). Gasification-based NH3 plants (many in China) include making pure H2 and CO2 separation at rates up to 3500 tCO2 d-1 per plant. South African plants making Fischer-Tropsch fuels and chemicals and a North Dakota plant making synthetic natural gas (SNG) from coal also produce large streams of nearly pure CO2. Figure 3.15 shows a picture of the North Dakota gasification plant in which 3.3 MtCO2 yr-1 is captured using a refrigerated methanol-based, physical solvent scrubbing process (Rectisol process, see Section 126.96.36.199 and Table 3.2). Most of this captured CO2 is vented and about 1.5 Mtonnes yr-1 of this stream is currently pipelined to the Weyburn, Canada enhanced oil recovery and CO2 storage project (see Chapter 5).
When CO2 capture is an objective, O2-blown and high-pressure systems are preferred because of the higher CO2 partial pressures. De-carbonization via gasification entails lower energy penalties for CO2 capture than does post-combustion capture when considering only the separation stage, because the CO2 can be recovered at partial pressures up to 3 orders of magnitude higher. This greatly reduces CO2 absorber size, solvent circulation rates and CO2 stripping energy requirements. However, additional energy penalties are incurred in shifting the CO in the syngas to CO2 and in other parts of the system (see examples for IGCC plant with CO2 capture in Figures 3.6 and 3.7). Recent analyses for bituminous coals (see, for example, IEA GHG, 2003) suggest using simple high-pressure
Figure 3.15 North Dakota coal gasification plant with 3.3 MtCO2 yr1 capture using a cold methanol, physical solvent process (cluster of 4 tall columns in the middle of the picture represent the H2S and CO2 capture processes; part of the captured stream is used for EOR with CO2 storage in Weyburn, Saskatchewan, Canada).
Figure 3.15 North Dakota coal gasification plant with 3.3 MtCO2 yr1 capture using a cold methanol, physical solvent process (cluster of 4 tall columns in the middle of the picture represent the H2S and CO2 capture processes; part of the captured stream is used for EOR with CO2 storage in Weyburn, Saskatchewan, Canada).
entrained-flow gasifiers with water slurry feed and direct water quench followed by 'sour' (sulphur-tolerant) shift reactors and finally co-removal of CO2 and H2S by physical absorption. With sour shifting, hot raw syngas leaving the gasifier requires only one cooling cycle and less processing. Oxygen requirements increase for slurry fed gasifiers and conversion efficiencies decline with higher cycle efficiency losses with quench cooling. Similar trends are also noted with a shift from bituminous to lower rank sub-bituminous coal and lignite (Breton and Amick, 2002). Some analyses (e.g., Stobbs and Clark, 2005) suggest that the advantages of pre-combustion over post-combustion de-carbonization may be small or disappear for low-rank coals converted with entrained-flow gasifiers. High-pressure, fluidized-bed gasifiers may be better suited for use with low-rank coals, biomass and various carbonaceous wastes. Although there are examples of successful demonstration of such gasifiers (e.g., the high temperature Winkler, Renzenbrink et al., 1998), there has been little commercial-scale operating experience.
The H2S in syngas must be removed to levels of tens of ppm for IGCC plants for compliance with SO2 emissions regulations and to levels much less than 1 ppm for plants that make chemicals or synthetic fuels, so as to protect synthesis catalysts. If the CO2 must be provided for storage in relatively pure form, the common practice would be to recover first H2S (which is absorbed more readily than CO2) from syngas (along with a small amount of CO2) in one recovery unit, followed by reduction of H2S to elemental sulphur in a Claus plant and tail gas clean-up, and subsequent recovery of most of the remaining CO2 in a separate downstream unit. An alternative option is to recover sulphur in the form of sulphuric acid (McDaniel and Hormick, 2002). If H2S/CO2 co-storage is allowed, however, it would often be desirable to recover H2S and CO2 in the same physical absorption unit, which would lead to moderate system cost savings (IEA GHG, 2003; Larson and Ren, 2003; Kreutz et al., 2005) especially in light of the typically poor prospects for selling byproduct sulphur or sulphuric acid. Although co-storage of H2S and CO2 is routinely pursued in Western Canada as an acid gas management strategy for sour natural gas projects (Bachu and Gunter, 2005), it is not yet clear that co-storage would be routinely viable at large scales - a typical gasification-based energy project would involve an annual CO2 storage rate of 1-4 Mtonnes yr-1, whereas the total CO2 storage rate for all 48 Canadian projects is presently only 0.48 Mtonnes yr-1 (Bachu and Gunter, 2005).
188.8.131.52 Integrated gasification combined cycle (IGCC) for power generation In a coal IGCC, syngas exiting the gasifier is cleaned of particles, H2S and other contaminants and then burned to make electricity via a gas turbine/steam turbine combined cycle. The syngas is generated and converted to electricity at the same site, both to avoid the high cost of pipeline transport of syngas (with a heating value only about 1/3 of that for natural gas) and to cost-effectively exploit opportunities for making extra power in the combined cycle's steam turbine using steam from syngas cooling. The main drivers for IGCC development were originally the prospects of exploiting continuing advances in gas turbine technology, the ease of realizing low levels of air-pollutant emissions when contaminants are removed from syngas, and greatly reduced process stream volumes compared to flue gas streams from combustion which are at low pressure and diluted with nitrogen from air.
Since the technology was initially demonstrated in the 1980s, about 4 GWe of IGCC power plants have been built. Most of this capacity is fuelled with oil or petcoke; less than 1 GWe of the total is designed for coal (IEA CCC, 2005) and 3 out of 4 plants currently operating on coal and/or petcoke. This experience has demonstrated IGCC load-following capability, although the technology will probably be used mainly in base load applications. All coal-based IGCC projects have been subsidized, whereas only the Italian oil-based IGCC projects have been subsidized. Other polygeneration projects in Canada, the Netherlands and the United States, as well as an oil-based IGCC in Japan, have not been subsidized (Simbeck, 2001a).
IGCC has not yet been deployed more widely because of strong competition from the natural gas combined cycle (NGCC) wherever natural gas is readily available at low prices, because coal-based IGCC plants are not less costly than pulverized coal fired steam-electric plants and because of availability (reliability) concerns. IGCC availability has improved in recent years in commercial-scale demonstration units (Wabash River Energy, 2000; McDaniel and Hornick, 2002). Also, availability has been better for industrial polygeneration and IGCC projects at oil refineries and chemical plants where personnel are experienced with the chemical processes involved. The recent rise in natural gas prices in the USA has also increased interest in IGCC.
Because of the advantages for gasification of CO2 capture at high partial pressures discussed above, IGCC may be attractive for coal power plants in a carbon-constrained world (Karg and Hannemann, 2004). CO2 capture for pre-combustion systems is commercially ready, however, no IGCC plant incorporating CO2 capture has yet been built. With current technology, average estimates of the energy penalties and the impact of increased fuel use for CO2 removal are compared with other capture systems in Figures 3.6 and 3.7 and show the prospective potential of IGCC options. The data in Figures 3.6 and 3.7 also show that some IGCC options may be different from others (i.e., slurry fed and quench cooled versus dry feed and syngas cooling) and their relative merits in terms of the capital cost of plant and the delivered cost of power are discussed in Section 3.7.
Relative to intensively studied coal IGCC technology with CO2 capture, there are few studies in the public domain on making H2 from coal via gasification with CO2 capture (NRC, 2004; Parsons 2002a, b; Gray and Tomlinson, 2003; Chiesa et al., 2005; Kreutz et al., 2005), even though this H2 technology is well established commercially, as noted above. With commercial technology, H2 with CO2 capture can be produced via coal gasification in a system similar to a coal IGCC plant with CO2 capture. In line with the design recommendations for coal IGCC plants described above (IEA GHG, 2003), what follows is the description from a design study of a coal H2 system that produces, using best available technology, 1070 MWt of H2 from high-sulphur (3.4%) bituminous coal (Chiesa et al., 2005; Kreutz et al., 2005). In the base case design, syngas is produced in an entrained flow quench gasifier operated at 7 MPa. The syngas is cooled, cleaned of particulate matter, and shifted (to primarily H2 and CO2) in sour water gas shift reactors. After further cooling, H2S is removed from the syngas using a physical solvent (Selexol). CO2 is then removed from the syngas, again using Selexol. After being stripped from the solvents, the H2S is converted to elemental S in a Claus unit and a plant provides tail gas clean-up to remove residual sulphur emissions; and the CO2 is either vented or dried and compressed to 150 atm for pipeline transport and underground storage. High purity H2 is extracted at 6 MPa from the H2-rich syngas via a pressure swing adsorption (PSA) unit. The PSA purge gas is compressed and burned in a conventional gas turbine combined cycle, generating 78 MW and 39 MW of electricity in excess of onsite electricity needs in the without and with CO2 capture cases, respectively. For this base case analysis, the effective efficiency of H2 manufacture was estimated to be 64% with CO2 vented and 61% with CO2 captured, while the corresponding emission rates are 16.9 kgCO2 and 1.4 kgCO2/ kgH2, respectively. For the capture case, the CO2 removal rate was 14.8 kgCO2/kgH2. Various alternative system configurations were explored. It was found that there are no thermodynamic or cost advantages from increasing the electricity/H2 output ratio, so this ratio would tend to be determined by relative market demands for electricity and H2. One potentially significant option for reducing the cost of H2 with CO2 capture to about the same level as with CO2 vented involves H2S/CO2 co-capture in a single Selexol unit, as discussed above.
As discussed in Chapter 2, clean synthetic high H/C ratio fuels can be made from syngas via gasification of coal or other low H/ C ratio feedstocks. Potential products include synthetic natural gas, Fischer-Tropsch diesel/gasoline, dimethyl ether, methanol and gasoline from methanol via the Mobil process. A byproduct is typically a stream of relatively pure CO2 that can be captured and stored.
Coal derived Fischer-Tropsch synfuels and chemicals have been produced on a commercial scale in South Africa; coal methanol is produced in China and at one US plant; and coal SNG is produced at a North Dakota (US) plant (NETL-DOE, 2002). Since 2000, 1.5 MtCO2 yr-1 from the North Dakota synthetic natural gas plant (see Figure 3.15) have been transported by pipeline, 300 km to the Weyburn oil field in Saskatchewan, Canada for enhanced oil recovery with CO2 storage.
Synfuel manufacture involves O2-blown gasification to make syngas, gas cooling, gas clean-up, water gas shift and acid gas (H2S/CO2) removal. Subsequently cleaned syngas is converted catalytically to fuel in a synthesis reactor and unconverted syngas is separated from the liquid fuel product. At this point either most unconverted gas is recycled to the synthesis reactor to generate additional liquid fuel and the remaining unconverted gas is used to make electricity for onsite needs, or syngas is passed only once through the synthesis reactor, and all unconverted syngas is used for other purposes, for example, to make electricity for sale to the electric grid as well as for onsite use. The latter once through option is often more competitive as a technology option (Williams, 2000; Gray and Tomlinson, 2001; Larson and Ren, 2003; Celik et al, 2005).
New slurry-phase synthesis reactors make the once through configuration especially attractive for CO-rich (e.g., coal-derived) syngas by making high once through conversion possible. For once through systems, a water gas shift reactor is often placed upstream of the synthesis reactor to generate the H2/CO ratio that maximizes synfuel conversion in the synthesis reactor. It is desirable to remove most CO2 from shifted syngas to maximize synthetic fuel conversion. Also, because synthesis catalysts are extremely sensitive to H2S and various trace contaminants, these must be removed to very low levels ahead of the synthesis reactor. Most trace metals can be removed at low-cost using an activated carbon filter. CO2 removal from syngas upstream of the synthesis reactor is a low-cost, partial de-carbonization option, especially when H2S and CO2 are co-captured and co-stored as an acid gas management strategy (Larson and Ren, 2003). Further de-carbonization can be realized in once through systems, at higher incremental cost, by adding additional shift reactors downstream of the synthesis reactor, recovering the CO2, and using the CO2-depleted, H2-rich syngas to make electricity or some mix of electricity plus H2 in a 'polygeneration' configuration (see Figure 3.16). The relative amounts of H2 and electricity produced would depend mainly on relative demands, as there do not seem to be thermodynamic or cost advantages for particular H2/electricity production ratios (Chiesa et al., 2005; Kreutz et al., 2005). When syngas is decarbonized both upstream and downstream of the synthesis reactor (see Figure 3.16) it is feasible to capture and store as CO2 up to 90% of the carbon in the original feedstock except
that contained in the synthetic fuel produced.
An example of such a system (Celik et al., 2005) is one making 600 MW of dimethyl ether (containing 27% of coal input energy and 20% of coal input carbon) plus 365 MW of electricity (no H2) from coal. For this system the CO2 storage rate (equivalent to 74% of C in coal) is 3.8 Mtonnes yr-1 (39% from upstream of the synthesis reactor). The estimated fuel cycle-wide GHG emissions for dimethyl ether are 0.9 times those for crude oil-derived diesel and those for electricity are 0.09 times those for a 43% efficient coal-fired power plant with CO2 vented.
Pressure Swing Adsorption (PSA) is the system of choice for the purification of syngas, where high purity H2 is required. However, it does not selectively separate CO2 from the other waste gases and so for an SMR application the CO2 concentration in the waste gas would be 40-50% and require further upgrading to produce pure CO2 for storage. Simultaneous H2 and CO2 separation is possible by using an additional PSA section to remove the CO2 prior to the H2 separation step, such as the Air Products Gemini Process (Sircar, 1979).
The PSA process is built around adsorptive separations of cyclic character. The cycles consist of two basic steps: adsorption, in which the more adsorbable species are selectively removed from the feed gas and regeneration (desorption), when these species are removed from the adsorbent so that it can be ready for the next cycle. It is possible to obtain useful products during both adsorption and regeneration. The principal characteristic of PSA processes is the use of a decrease in pressure and/or the purge by a less adsorbable gas to clean the adsorbent bed. Apart from adsorption and regeneration, a single commercial PSA cycle consists of a number of additional steps, including co-and counter-current pressurization, pressure equalization and co- and counter-current depressurization. A detailed description of the PSA technique, along with its practical applications can be found elsewhere (Ruthven et al., 1994).
means of a chemical reaction, which can be reversed by pressure reduction and heating. The tertiary amine methyldiethanolamine (MDEA, see Table 3.2) is widely used in modern industrial processes, due to the high CO2 loading possible and the low regenerator heating load, relative to other solvents. Hot potassium carbonate (the most common commercial version of which is known as Benfield) was used for CO2 removal in most hydrogen plants until about 15 years ago.
Physical solvent (or absorption) processes are mostly applicable to gas streams which have a high CO2 partial pressure and/or a high total pressure. They are often used to remove the CO2 from the mixed stream of CO2 and H2 that comes from the shift reaction in pre-combustion CO2 capture processes, such as product from partial oxidation of coal and heavy hydrocarbons.
The leading physical solvent processes are shown in Table 3.2. The regeneration of solvent is carried out by release of pressure at which CO2 evolves from the solvent, in one or more stages. If a deeper regeneration is required the solvent would be stripped by heating. The process has low energy consumption, as only the energy for pressurizing the solvent (liquid pumping) is required.
The use of high sulphur fossil fuels in a pre-combustion capture process results in syngas with H2S. Acid gas components must be removed. If transport and storage of mixed CO2 and H2S is possible then both components can be removed together. Sulphinol was developed to achieve significantly higher solubilities of acidic components compared to amine solvents, without added problems of excessive corrosion, foaming, or solution degradation. It consists of a mixture of sulpholane (tetrahydrothiophene 1,1-dioxide), an alkanolamine and water in various proportions depending on the duty. If pure CO2 is required, then a selective process is required using physical solvents - often Rectisol or Selexol. The H2S must be separated at sufficiently high concentration (generally >50%) to be treated in a sulphur recovery plant.
Chemical solvents are used to remove CO2 from syngas at partial pressures below about 1.5 MPa (Astarita et al., 1983) and are similar to those used in post-combustion capture (see Section 184.108.40.206). The solvent removes CO2 from the shifted syngas by
Pre-combustion capture includes reforming, partial oxidation or gasification. In order to maintain the operability of the catalyst of reformers, sulphur (H2S) has to be removed prior to reforming. In gasification, sulphur can be captured from the syngas, and in the case when liquid or solid fuels are gasified, particulates, NHj, COS and HCN are also present in the system that need to be removed. In general, all of these pollutants can be removed from a high-pressure fuel gas prior to combustion, where combustion products are diluted with nitrogen and excess oxygen. In the combustion of hydrogen or a hydrogen-containing fuel gas, NO may be formed. Depending upon combustion technology and hydrogen fraction, the rate at which NOx is formed may vary. If the volumetric fraction of hydrogen is below approximately 50-60%, NOx formation is at the same level as for natural gas dry low-NO systems (Todd and Battista, 2001). x
In general, with the exception of H2S that could be co-removed with CO2, other pollutants identified above are separated in additional pretreatment operations, particularly in systems that gasify liquid or solid fuels. High temperature pretreatment operations for these multi-pollutants that avoid cooling of the syngas have the advantage of improving the cycle efficiency of the overall gasification process, but these separation processes have not been commercially demonstrated.
Although it is not yet regulated as a 'criteria pollutant', mercury (Hg), is currently the focus of considerable concern as a pollutant from coal power systems. For gasification systems Hg can be recovered from syngas at ambient temperatures at very low-cost, compared to Hg recovery from flue gases (Klett et al., 2002).
Emerging options in both natural gas reforming and coal gasification incorporate novel combined reaction/separation systems such as sorption-enhanced reforming and sorption-enhanced water gas shift, membrane reforming and membrane water gas shift. Finally there is a range of technologies that make use of the carbonation of CaO for CO2 capture.
A concept called Sorption Enhanced Reaction (SER) uses a packed bed containing a mixture of a catalyst and a selective adsorbent to remove CO2 from a high temperature reaction zone, thus driving the reaction to completion. (Hufton et al., 1999). The adsorbent is periodically regenerated by using a pressure swing, or temperature swing adsorption system with steam regeneration (Hufton et al., 2005).
High temperature CO2 adsorbents such as hydrotalcites (Hufton et al., 1999) or lithium silicate (Nakagawa and Ohashi, 1998) can be mixed with a catalyst to promote either the steam methane reforming reaction (Reaction 1) or water gas shift reaction (Reaction 3) producing pure hydrogen and pure CO2 in a single process unit. The continuous removal of the CO2 from the reaction products by adsorption shifts each reaction towards completion.
The SER can be used to produce hydrogen at 400-600oC to fuel a gas turbine combined cycle power generation system. A design study based on a General Electric 9FA gas turbine with hot hydrogen, produced from an air blown ATR with a sorption enhanced water gas shift reactor, gave a theoretical net efficiency of 48.3% with 90% CO2 capture at 99% purity and 150 bar pressure (Hufton et al., 2005). The process is currently at the pilot plant stage.
220.127.116.11 Membrane reactors for hydrogen production with CO2 capture
Inorganic membranes with operating temperatures up to 1000°C offer the possibility of combining reaction and separation of the hydrogen in a single stage at high temperature and pressure to overcome the equilibrium limitations experienced in conventional reactor configurations for the production of hydrogen. The combination of separation and reaction in membrane steam reforming and/or membrane water gas shift offers higher conversion of the reforming and/or shift reactions due to the removal of hydrogen from these equilibrium reactions as shown in Reactions (1) and (3) respectively. The reforming reaction is endothermic and can, with this technique, be forced to completion at lower temperature than normal (typically 500-600°C). The shift reaction being exothermic can be forced to completion at higher temperature (500-600°C).
Another reason to incorporate H2 separation membranes in the hydrogen production system is that CO2 is also produced without the need for additional separation equipment. Membrane reactors allow one-step reforming, or a single intermediate water gas shift reaction, with hydrogen separation (the permeate) leaving behind a retentate gas which is predominantly CO2 and a small amount of non-recovered hydrogen and steam. This CO2 remains at the relatively high pressure of the reacting system (see Figure 3.17). Condensation of the steam leaves a concentrated CO2 stream at high pressure, reducing the compression energy for transport and storage. Membrane reforming will benefit from high-pressure operation due to the increased H2 partial pressure differential across the membrane which is the driving force for hydrogen permeation. Therefore membrane reactors are also seen as a good option for pre-combustion de-carbonization where a low-pressure hydrogen stream for fuel gas and a high-pressure CO2-rich stream for transport and storage are required. The use of the membrane reformer reactor in a gas turbine combined cycle means that the hydrogen needs to be produced at such pressure that the significant power consumption for the hydrogen compression is avoided. This could be done by increasing the operating pressure of the membrane reactor or by using a sweep gas, for instance steam, at the permeate side of the membrane (Jordal et al., 2003).
For these membrane reactor concepts, a hydrogen selective membrane capable of operating in a high-temperature, high-pressure environment is needed. In the literature a number of membrane types have been reported that have these capabilities and these are listed in Table 3.3. Microporous inorganic membranes based upon surface diffusion separation exhibit rather low separation factors (e.g., H2/CO2 separation factor of 15). However, the separation ability of the current commercially available gamma-alumina and silica microporous membranes (which have better separation factors, up to 40) depends upon the stability of the membrane pore size, which is adversely
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