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Wet scrubbing and gas filtration of syngas in IGCC systems
Wet scrubbing and gas filtration of syngas in IGCC systems
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Herbert M. Kosstrin Leidos Engineering, L.L.C
10.1 Introduction The generation of power from solid fuels such as coal, petroleum coke, and biomass needs to take into account the control of environmental emissions and other potential contaminants that can affect the combustion process negatively. As discussed later, the contaminants of interest include particulates (char and solid inorganic compounds), chlorine, sulfur, volatile metals, and unreacted hydrocarbons. The conversion of solid fuels to power can be accomplished in integrated gasification combined cycle (IGCC) systems or in steam boiler-based units. IGCC systems consist of a gasifier producing a syngas, a syngas cleanup system and a combustion turbine in a combined-cycle mode of operation, and can be based on coal (and petroleum coke) or biomass-type fuels. IGCC systems have shown to be environmentally superior to direct combustion boiler-based systems. In boiler-based power systems, the control of environmental emissions is performed primarily after combustion has been completed by processing the flue gas through pollution-control equipment. In some cases, the coal is cleaned prior to combustion to reduce the level of ash and sulfur; however, post-combustion cleanup is still required. The post-combustion cleanup equipment is designed to remove particulate, sulfur compounds, chlorine compounds, and, more recently, mercury compounds. The resulting solid waste produced from the capture of the coal ash and sulfur compounds in the form of calcium sulfate in most cases need to be disposed of in landfills or ash ponds. IGCC systems capture the pollutants from a smaller concentrated gas stream before combustion than the post-combustion gas cleanup system used in the conventional boiler systems. This results in small lowercost equipment. In addition the sulfur in this syngas stream can be captured as a byproduct as opposed to be disposed of as a waste. The remainder of this chapter will focus on discussing pollution control processes in IGCC systems.
10.2 Contaminants removal of coal-based IGCC systems Removal of environmental contaminants in the IGCC systems uses multi-staged unit operations, each addressing specific items and results in improved capture of the contaminates. A second purpose of cleaning the syngas is to prepare the syngas for use Integrated Gasification Combined Cycle (IGCC) Technologies. DOI: http://dx.doi.org/10.1016/B978-0-08-100167-7.00010-X © 2017 Elsevier Ltd. All rights reserved.
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as a combustion turbine fuel. The initial syngas cleanup unit operation in an IGCC system is wet scrubbing and particulate removal (WS/PR). The use of coal and biomass in IGCC systems has taken different approaches resulting in slightly different syngas cleanup systems. In general, coal-based systems have incorporated high-temperature (>1320°C/2400°F) slagging gasifiers to maximize the carbon conversion into syngas. This type of gasifier produces a tar free syngas. The new Kemper County IGCC operates at approximately 1000°C/1825°F in the mixing zone in the gasifier and is also not expected to produce any significant tars. Biomassbased IGCC systems do not need to operate at such high temperatures to maximize carbon conversion. Typical operating temperatures are approximately 820°C (1500°F). At these temperatures, the biomass ash does not slag; however, the syngas contains tars which are detrimental to the combustion turbine portion of the IGCC and need to be removed or destroyed. In either approach, the syngas that is produced contains the chemical contaminants that were contained in the fuel (chlorines, sulfurs, and volatile metals) and the solid residue of unconverted carbon and ash. In high-temperature entrained flow slagging gasifiers most of the inorganic ash material remains in the slag and is not in the syngas; while in the biomass-based units all of the inorganic ash material is in the syngas along with the unreacted char and tars. The combustion turbine portion of the IGCC system needs a syngas cleaned of contaminants and tars. The chemical components of the syngas include compounds that are needed as fuel for the combustion turbine (hydrogen, carbon monoxide, and methane), inert compounds, such as carbon dioxide, nitrogen and argon, and compounds that need to be removed to minimize environmental emissions or are detrimental to the performance of the combustion turbine. These contaminants include chlorine, sulfur compounds, nitrogen compounds, particulate, and volatile metals. For biomass-based systems, tars must also be destroyed or removed. In the case of a coal-based IGCC, as opposed to coal combustion, the final disposition of the sulfur is as a product (sulfur or sulfuric acid) and the ash is primarily an inert slag which has potential uses as an aggregate. For biomass-based IGCC systems, the ash may have beneficial uses as a soil amendment. No ash ponds or potentially unmarketable sulfur products are produced. The gases and compounds of interest are listed in Table 10.1. Table 10.1
Compounds of concern
Compounds
Item of concern
Chlorine
Corrosion of equipment, catalyst degradation, and emissions Emissions Emissions Emissions Emissions Catalyst plugging and emissions Catalyst degradation and emissions Emissions
Hydrogen sulfide (H2S) Carbonyl sulfide (COS) Ammonia (NH3) Hydrogen cyanide (HCN) Particulate Arsenic Mercury
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Figure 10.1 Syngas cleanup operations.
Collectively, these gaseous compounds and solids are the compounds that are undesirable. In the IGCC system, these compounds need to be removed or minimized prior to the final syngas being delivered to the combustion turbine. The traditional syngas cleanup steps included particulate removal, wet scrubbing (for chlorine and NH3 removal), hydrolysis (for conversion of COS to H2S, and HCN to NH3), syngas cooling, activated carbon beds for mercury and volatile metals removal, and acid gas systems (physical and chemical solvents) for sulfur removal. Fig. 10.1 is a block flow diagram showing the several unit operations between the gasifier and the combustion turbine. The unit operations after wet scrubbing and particulate removal (WS/PR) act as a primary unit for certain compounds (sulfur, volatile metals) and polishing for the WS/PR units. For example, the cooling step condenses the water from the syngas while simultaneously removing HCL and some NH3 that remains in the syngas. The acid gas removal unit, the primary purpose of which is to remove H2S, also removes some COS. The importance of removing NH3 (fuel-bound nitrogen to the combustion turbine) is to limit the generation of oxides of nitrogen in the exhaust of the combustion turbine. Likewise, removal of the sulfur compounds is to limit sulfur dioxide emissions from the combustion turbine. Particulate removal can be accomplished in dry systems utilizing cyclones or barrier filters and in wet systems as part of a wet scrubbing unit. Dry particulate removal allows for the direct recycling of unreacted carbon to enhance the efficiency of the system. Historically, cyclones have been the available method for dry particulate removal. These units have the advantage of requiring only a low-pressure drop, and are favored by low-pressure gasifiers. However, cyclones have several limitations. Firstly, the particulate removal efficiency at the design particle size and syngas flow rate is typically a maximum of 99%, requiring additional particulate removal downstream of this unit. Secondly, the efficiency at lower flow rates decreases allowing more particulate to remain in the syngas, thus, at reduced operating rates of the gasifier, additional particulate needs to be controlled by downstream equipment. Lastly, if the particles’ size distribution tends to contain smaller particles than the design assumptions, additional particulate remains in the syngas. As a consequence of these limitations, cyclones can be part of a particulate removal system; however, they are not a total particulate removal solution. The newer barrier filters address these limitations in cyclones and can be a singular solution to particulate removal; however, they require a higher pressure drop and a pressurized gasifier. This technology allows nearly complete particulate removal and is not affected by reduced operating rates. However, the singular particulate removal device does not address the removal of chemical compounds, which is addressed later.
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Figure 10.2 Wet scrubbing approach to initial syngas cleanup.
Figure 10.3 Dry particulate approach to initial syngas cleaning.
For coal-based IGCC plants, the two primary approaches to WS/PR can be seen in the General Electric system design (Polk County and Edwardsport) (Fig. 10.2) and the E-Gas design (Wabash River) (Fig. 10.3). As shown in Fig. 10.1, the first unit operation after the WS/PR is either the catalytic hydrolysis unit (traditional design) or the water-gas-shift unit (carbon dioxide removal design) which replaces the hydrolysis unit. These catalytic units are affected negatively by particulates (plugging of the catalyst pores), and chlorine (deactivation of the catalyst). These catalytic units are sulfur tolerant. WS/PR does not act on sulfur, HCN, or volatile metals such as mercury, and only partially removes NH3.
10.2.1 Wet scrubbing In the wet scrubbing approach as practiced by General Electric and others, the syngas is contacted with water in a venture-type scrubber. This cools the syngas to approximately the saturation temperature at operating pressure (approximately 200°C/400°F in an IGCC configuration), scrubs out the solid particulate and removes chlorine and some NH3. The scrubbing water also absorbs a minor amount of carbon dioxide. The materials of construction of these wet scrubbing systems need to take into consideration the potentially acidic nature of the water (from the chlorine, and carbon dioxide). The liquid effluent from this system contains unconverted coal (char), coal ash that did not form a slag, chlorine, and NH3 compounds. This liquid effluent is further processed in a clarifier to concentrate the char and ash particles in a stream known as black water and a cleaner stream known as gray water. The gray water is recycled to the scrubber and/or the gasifier and the black water is further processed in a wastewater treatment system. As an enhancement to the efficiency of the overall IGCC plant, the carbon-rich
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solids in the black water can be removed and recycled to the gasifier. In a slurry gasifier, such as the GE technology, this is accomplished by returning these solids to the coal slurry. In a dry feed gasifier, such as a Siemens gasifier, these solids must be dried to be used with the coal feed.
10.2.2 Dry particulate removal The alternative approach is to remove the solids in a dry state, and subsequently scrub the syngas with water to remove the chlorine. The E-Gas technology uses hightemperature metallic barrier-type filters operating at approximately 400°C (750°F) to remove the unconverted char and coal ash from the syngas stream. This stream of solids is then returned to the high-temperature slagging stage of the E-Gas gasifier to convert the carbon to syngas and the ash to slag. The particulate free syngas is then scrubbed with water to remove chlorine. This is an important step, since the metallurgy of the downstream equipment is affected negatively by chlorine. The chlorine, in the form of hydrochloric acid, can both deactivate catalysts and attack the materials of construction of equipment when the syngas is cooled further, to provide the appropriate temperature for mercury removal and acid gas removal (approximately 38°C/100°F). Depending on the amount of the condensed acid and the materials of construction, the deterioration of the equipment can be slow or rapid. Capturing the solids in a dry state and immediately recycling to the gasifier removes the venture scrubber, the attendant gray water/black water system, and the equipment to capture the wet char for recycling. The high-temperature particulate filters can be either metallic or ceramic (Knight et al., 2014). The design of the filter system must incorporate safeguards to address broken filters that would allow particulate matter to get into the remainder of the cleanup train and require immediate maintenance. The wet scrubbing system typically does not encounter this type of particulate breakthrough.
10.3 Contaminants removal from biomass-based IGCC systems Biomass-based IGCCs have somewhat different cleanup systems compared to coalbased IGCCs in that the removal of tars must be addressed. Two approaches to tar removal are available. One is the addition of a higher-temperature step after gasification to crack the tars to shorter-chain hydrocarbons that are compatible with the combustion turbine. The second approach is a specially designed scrubbing system. However, biomass IGCCs still require removal of particulates and the chemical contaminants. As with a coal-based IGCC, the specific cleanup system between the gasifier and the combustion turbine must take into consideration the specific contaminates in the biomass feedstock. Sulfur levels in most biomass are low and, as such, downstream sulfur removal may not be required. However, they still require the removal of particulates and the chemical contaminates. The following discussion is based on a woody feedstock and a fluidized bed-type of gasifier. In these units, cyclones are used for initial particulate capture and char
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recycle to enhance carbon conversion and efficiency of the system. Biomass-based IGCCs typically operate at temperatures that are below the slagging temperature of the feedstock. Thus, the ash components are not slagged. In addition, these systems operate at pressures that are lower than the operational pressures of combustion turbines, and compression of the syngas is required at a point in the syngas processing train. As previously noted, with the lower operating temperatures (typically in the 820°C/1500°F range), the syngas contains tars that need to be removed prior to the compressions step where tars would condense and cause maintenance and availability problems. The removal of the tars is necessary to prevent fouling of compressors and combustion equipment. In the case of a high-pressure biomass gasifier (greater than 30 bar pressure), where no compression step were needed, the fuel requirements of the combustion turbines (no condensable hydrocarbons at the combustor inlet temperature) would still require tar removal. Several approaches to tar removal have been suggested for biomass-based systems. One approach increases the temperature of the syngas to 990°C (1800°F) or higher to crack the tars to shorter chain hydrocarbons. This can be accomplished by passing the syngas through a high-temperature sand bed (Paisley et al., 2007), adding direct oxygen to raise the syngas temperature in the freeboard of the fluidized gasifier, adding a catalytic tar converter (Knight et al., 2014), or a natural gas-based hot oxygen burner in a separate partial oxidation reactor. The design needs to take into consideration the temperature at which the biomass ash creates a slag (typically approximately 1100°C/2000°F, although some biomass materials have lower slagging temperatures). Raising the temperature into the ash slagging range may destroy all of the tars; however, the liquid ash needs to be handled. What the non-slagging systems have in common is that they do not necessarily destroy all of the tars completely (some light shorterchain tars may remain, such as benzene and naphthalene). These tar-cracking units are typically followed by wet scrubbers. The wet scrubbers serve to remove chlorine, NH3, some of the benzene, and any remaining particles. However, naphthalene can condense to a solid and leave the scrubber and an additional particulate filter may be required. The short chain tars that remain in the syngas are burned in the combustion turbine. The use of the catalytic tar converter requires a high-temperature barrier filter prior to the catalytic converter to remove particulate matter to protect the catalyst from fouling. Some designs do not incorporate a high-temperature unit and instead use a multiphase or multiple scrubbers. These scrubbers utilize a combination of oil-based scrubbers (to remove the non-water soluble tars, for example) (Konemann and Zwart, 2007) followed by water-based scrubber systems for chlorine and partial NH3 removal. In either case, naphthalene, which is a highly refractory hydrocarbon, is difficult to destroy or remove completely. Although a vapor, at high temperatures this material becomes solid at lower temperatures and is typically filtered out prior to compression.
10.4 Efficiency of IGCC systems as related to WS/PR As discussed in other chapters, for example syngas cooling in Chapter 9, Syngas cooling in IGCC systems, IGCC systems incorporate several means of heat recovery
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to enhance the efficiency of the overall process. However, overall carbon conversion is a key metric in enhancing overall process efficiency. A secondary consideration is any change in power consumption to achieve the recycle of the unconverted carbon. The gasification systems usually do not fully convert all of the carbon to syngas on the first pass through the gasifier and recycling of this unconverted carbon can enhance the efficiency of conversion of the energy in the solid fuel to power by approximately 2 to 4%. As discussed above, both the wet scrubbing and dry particulate approach can recycle unconverted carbon to the gasifier to enhance carbon conversion. The dry particulate removal approach (barrier filters and cyclones) maximizes the carbon conversion by approaching nearly complete carbon recycle, while the wet scrubbing approach tends to lose some carbon in the water processing process. Typically, approximately 70% of the unconverted carbon from the water system is recovered. A secondary item is the moisture content of the recycled material. The drier the material, the less energy required to gasify the recycled carbon. Overall, the dry particulate approach has an advantage in efficiency enhancement over the wet scrubbing approach. In biomass-based IGCCs, unreacted carbon can also be recycled back to the gasifier as a dry particulate (from cyclones or barrier filters), and as captured tar from the scrubbers. Each system must be investigated to determine the best approach to accomplish the enhanced efficiency goal.
10.5 New technologies The capture of carbon dioxide is a feature that was not incorporated in IGCC units until recently. IGCC systems built in the 1990s, such as Wabash River (DOE Topical Report 20, September 2000), and Polk County (DOE Topical Report 19, July 2000) in the US and Buggenum (EPRI Report, 2007), and Puertollano (Radtke, HeinritzAdrain, Hooper and Richards, 2008) in Europe did not include carbon capture and had simpler syngas cleanup and conversion subsystems. The newer (2014) Edwardsport IGCC (Zupan, 2009) also did not capture carbon dioxide (although it is stated to be carbon capture ready). However, the Kemper County (Southern Company, 2011) under construction in 2015 has partial carbon capture (65%) and the Texas Clean Coal Project (NETL Technical Note, 2014) (under development in 2015) has a 90% carbon capture design. The addition of maximum carbon dioxide capture changes the design of the syngas conversion and cleanup train, by incorporating water-gas-shift reactors (which replace the COS hydrolysis reactor in Fig. 10.1) and a more robust acid gas removal process (sulfur and carbon dioxide). In either case, the first unit operation after the syngas exits the gasification unit is the WS/PR. High-temperature plasma units (see Chapter:Municipal wastes and other potential fuels for use in IGCC systems) are being developed for municipal waste and hazardous waste feedstocks (a large-scale unit is under construction at Teeside in the United Kingdom) are similar to slagging coal gasifiers in their WS/PR units. The plasma systems typically operate at above the slagging temperature of the biomass and do not produce tars.
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The introduction of new technologies into IGCC systems can influence WS/PR in two separate regimes. Improvements in the capability of barrier filters to operate at higher temperatures (currently available in 2016 to 730°C/1350°F) widens the flexibility of design engineers to improve the overall efficiency of systems by allowing for high-temperature heat recovery without the potential fouling of the heat exchanger or downstream catalytic converters. Higher temperature particulate filters are currently available (see Pall) that can have an impact on the efficiencies of biomass-based IGCCs. The use of catalytic tar crackers requires a particulate-free syngas. Designs that incorporate a high-temperature filter (greater than 820°C/1500°F) can eliminate the need to cool the syngas prior to entering the tar cracker, and minimize or eliminate the need to add an oxidant to raise the temperature of the syngas to enable the catalyst to operate effectively. In addition to filtering the syngas prior to a high-temperature heat recovery, such filters tend to reduce fouling of the heat exchanger and can result in better availability. Carbon capture or the removal of carbon dioxide from the syngas in an IGCC does not change the basic design of the WS/PR unit operation. The differences are downstream of the WS/PR operation, and the requirements for the removal of the bad actors addressed by WS/PR remains the same. Traditionally, sulfur removal has been incorporated into IGCC systems at the cold end of the process after the syngas has been cleaned of mercury (at approximately 38°C/100°F). The systems commercially available (chemical and physical absorbents) provide better removal of sulfur compounds (primarily H2S) at low temperatures. Recently, RTI developed a hot sulfur removal process, which has been piloted at the Tampa Electric IGCC since 2014. This system contacts the syngas with a solid adsorbent, removing the sulfur to levels of approximately 5 parts per million. The current design has this hot sulfur removal system after the particulate removal device. For the Tampa Electric unit, this is after the wet scrubber. The placement of this unit does not affect the current designs of the WS/PR systems; however, implementation may require additional particulate removal downstream to protect the combustion turbine form carryover of the solid sorbent.
References Department of Energy Topical Report No. 19, 2000. The Tampa electric integrated gasification combined cycle project, an update, July 2000. Department of Energy Topical Report No. 20, 2000. the Wabash River coal gasification repowering project, an update, September 2000. EPRI Report, 2007. Integrated gasification combined cycle (IGCC) design considerations for high avalibility, volume I: lessons from existing operations, technical update March 2007. Knight, R., Udengaard, N., Bryan, B., Patel, J., Jensen, J., Jokela, P., et al., 2014. Woody biomass to gasoline: pilot biorefinery test results, Symposium on Thermal and Catalytic Eciences for Biofuels and Biomass Products September 2014. Konemann, J.-W., Zwart, R., 2007. Olga tar removal, 4 MWt commercial demonstration biomass gasification in France, Gasification Technologies conference 2007.
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NETL Technical Note, 2014. Summit Texas clean energy < LLC: Texas clean energy project; Pre-Combustion CO2 Capture and Sequestration 2014. Paisley, M., Corley, R., Dayton, D., 2007. Advanced biomass gasification for the economical productin of power, fuels and hydrogen-implementation in montgomery New York, 15th European Biomass Conference and Exposition Berlin 2007. Radtke, K., Heinritz-Adrain, M., Hooper, M., Richards, B., 2008. 10 years operating experience at ELCOGAS IGCC, Puertollano, Spain, Gasification Technologies Conference 2008. Southern Company, 2011. CO2 capture at the Kemper County IGCC project, NETL CO2 Capture Technology Meeting 2011. Zupan, D., 2009. Edwardsport IGCC moving forward, Gasification Technologies Conference 2009.
Biography
Dr. Kosstrin is a Managing Director in Leidos Engineering, LLC (Leidos), and is a Leidos technical fellow. Dr. Kosstrin has over 40 years of experience in the development, demonstration, and evaluation of processes to enhance environmental performance, produce alternative fuels, and provide alternative sources of power generation. He has been involved in the technical development, feasibility analysis and/or independent review of a variety of gasification technologies using a wide range of feedstocks including coal, biomass and wastes. He is familiar with fixed bed, fluidized bed and entrained flow systems utilizing coal and/or biomass, including municipal solid waste and refuse-derived fuel (RDF). These systems were designed to produce either low Btu gas, medium Btu gas or synthesis gas which was used to fire boilers, gas turbines or provide a feedstock for chemicals (hydrogen, ammonia, urea, methanol, etc.) and fuels (diesel, gasoline, ethanol, and crude-type oils).
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Herbert M. Kosstrin Leidos Engineering, L.L.C
10.1 Introduction The generation of power from solid fuels such as coal, petroleum coke, and biomass needs to take into account the control of environmental emissions and other potential contaminants that can affect the combustion process negatively. As discussed later, the contaminants of interest include particulates (char and solid inorganic compounds), chlorine, sulfur, volatile metals, and unreacted hydrocarbons. The conversion of solid fuels to power can be accomplished in integrated gasification combined cycle (IGCC) systems or in steam boiler-based units. IGCC systems consist of a gasifier producing a syngas, a syngas cleanup system and a combustion turbine in a combined-cycle mode of operation, and can be based on coal (and petroleum coke) or biomass-type fuels. IGCC systems have shown to be environmentally superior to direct combustion boiler-based systems. In boiler-based power systems, the control of environmental emissions is performed primarily after combustion has been completed by processing the flue gas through pollution-control equipment. In some cases, the coal is cleaned prior to combustion to reduce the level of ash and sulfur; however, post-combustion cleanup is still required. The post-combustion cleanup equipment is designed to remove particulate, sulfur compounds, chlorine compounds, and, more recently, mercury compounds. The resulting solid waste produced from the capture of the coal ash and sulfur compounds in the form of calcium sulfate in most cases need to be disposed of in landfills or ash ponds. IGCC systems capture the pollutants from a smaller concentrated gas stream before combustion than the post-combustion gas cleanup system used in the conventional boiler systems. This results in small lowercost equipment. In addition the sulfur in this syngas stream can be captured as a byproduct as opposed to be disposed of as a waste. The remainder of this chapter will focus on discussing pollution control processes in IGCC systems.
10.2 Contaminants removal of coal-based IGCC systems Removal of environmental contaminants in the IGCC systems uses multi-staged unit operations, each addressing specific items and results in improved capture of the contaminates. A second purpose of cleaning the syngas is to prepare the syngas for use Integrated Gasification Combined Cycle (IGCC) Technologies. DOI: http://dx.doi.org/10.1016/B978-0-08-100167-7.00010-X © 2017 Elsevier Ltd. All rights reserved.
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as a combustion turbine fuel. The initial syngas cleanup unit operation in an IGCC system is wet scrubbing and particulate removal (WS/PR). The use of coal and biomass in IGCC systems has taken different approaches resulting in slightly different syngas cleanup systems. In general, coal-based systems have incorporated high-temperature (>1320°C/2400°F) slagging gasifiers to maximize the carbon conversion into syngas. This type of gasifier produces a tar free syngas. The new Kemper County IGCC operates at approximately 1000°C/1825°F in the mixing zone in the gasifier and is also not expected to produce any significant tars. Biomassbased IGCC systems do not need to operate at such high temperatures to maximize carbon conversion. Typical operating temperatures are approximately 820°C (1500°F). At these temperatures, the biomass ash does not slag; however, the syngas contains tars which are detrimental to the combustion turbine portion of the IGCC and need to be removed or destroyed. In either approach, the syngas that is produced contains the chemical contaminants that were contained in the fuel (chlorines, sulfurs, and volatile metals) and the solid residue of unconverted carbon and ash. In high-temperature entrained flow slagging gasifiers most of the inorganic ash material remains in the slag and is not in the syngas; while in the biomass-based units all of the inorganic ash material is in the syngas along with the unreacted char and tars. The combustion turbine portion of the IGCC system needs a syngas cleaned of contaminants and tars. The chemical components of the syngas include compounds that are needed as fuel for the combustion turbine (hydrogen, carbon monoxide, and methane), inert compounds, such as carbon dioxide, nitrogen and argon, and compounds that need to be removed to minimize environmental emissions or are detrimental to the performance of the combustion turbine. These contaminants include chlorine, sulfur compounds, nitrogen compounds, particulate, and volatile metals. For biomass-based systems, tars must also be destroyed or removed. In the case of a coal-based IGCC, as opposed to coal combustion, the final disposition of the sulfur is as a product (sulfur or sulfuric acid) and the ash is primarily an inert slag which has potential uses as an aggregate. For biomass-based IGCC systems, the ash may have beneficial uses as a soil amendment. No ash ponds or potentially unmarketable sulfur products are produced. The gases and compounds of interest are listed in Table 10.1. Table 10.1
Compounds of concern
Compounds
Item of concern
Chlorine
Corrosion of equipment, catalyst degradation, and emissions Emissions Emissions Emissions Emissions Catalyst plugging and emissions Catalyst degradation and emissions Emissions
Hydrogen sulfide (H2S) Carbonyl sulfide (COS) Ammonia (NH3) Hydrogen cyanide (HCN) Particulate Arsenic Mercury
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Figure 10.1 Syngas cleanup operations.
Collectively, these gaseous compounds and solids are the compounds that are undesirable. In the IGCC system, these compounds need to be removed or minimized prior to the final syngas being delivered to the combustion turbine. The traditional syngas cleanup steps included particulate removal, wet scrubbing (for chlorine and NH3 removal), hydrolysis (for conversion of COS to H2S, and HCN to NH3), syngas cooling, activated carbon beds for mercury and volatile metals removal, and acid gas systems (physical and chemical solvents) for sulfur removal. Fig. 10.1 is a block flow diagram showing the several unit operations between the gasifier and the combustion turbine. The unit operations after wet scrubbing and particulate removal (WS/PR) act as a primary unit for certain compounds (sulfur, volatile metals) and polishing for the WS/PR units. For example, the cooling step condenses the water from the syngas while simultaneously removing HCL and some NH3 that remains in the syngas. The acid gas removal unit, the primary purpose of which is to remove H2S, also removes some COS. The importance of removing NH3 (fuel-bound nitrogen to the combustion turbine) is to limit the generation of oxides of nitrogen in the exhaust of the combustion turbine. Likewise, removal of the sulfur compounds is to limit sulfur dioxide emissions from the combustion turbine. Particulate removal can be accomplished in dry systems utilizing cyclones or barrier filters and in wet systems as part of a wet scrubbing unit. Dry particulate removal allows for the direct recycling of unreacted carbon to enhance the efficiency of the system. Historically, cyclones have been the available method for dry particulate removal. These units have the advantage of requiring only a low-pressure drop, and are favored by low-pressure gasifiers. However, cyclones have several limitations. Firstly, the particulate removal efficiency at the design particle size and syngas flow rate is typically a maximum of 99%, requiring additional particulate removal downstream of this unit. Secondly, the efficiency at lower flow rates decreases allowing more particulate to remain in the syngas, thus, at reduced operating rates of the gasifier, additional particulate needs to be controlled by downstream equipment. Lastly, if the particles’ size distribution tends to contain smaller particles than the design assumptions, additional particulate remains in the syngas. As a consequence of these limitations, cyclones can be part of a particulate removal system; however, they are not a total particulate removal solution. The newer barrier filters address these limitations in cyclones and can be a singular solution to particulate removal; however, they require a higher pressure drop and a pressurized gasifier. This technology allows nearly complete particulate removal and is not affected by reduced operating rates. However, the singular particulate removal device does not address the removal of chemical compounds, which is addressed later.
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Figure 10.2 Wet scrubbing approach to initial syngas cleanup.
Figure 10.3 Dry particulate approach to initial syngas cleaning.
For coal-based IGCC plants, the two primary approaches to WS/PR can be seen in the General Electric system design (Polk County and Edwardsport) (Fig. 10.2) and the E-Gas design (Wabash River) (Fig. 10.3). As shown in Fig. 10.1, the first unit operation after the WS/PR is either the catalytic hydrolysis unit (traditional design) or the water-gas-shift unit (carbon dioxide removal design) which replaces the hydrolysis unit. These catalytic units are affected negatively by particulates (plugging of the catalyst pores), and chlorine (deactivation of the catalyst). These catalytic units are sulfur tolerant. WS/PR does not act on sulfur, HCN, or volatile metals such as mercury, and only partially removes NH3.
10.2.1 Wet scrubbing In the wet scrubbing approach as practiced by General Electric and others, the syngas is contacted with water in a venture-type scrubber. This cools the syngas to approximately the saturation temperature at operating pressure (approximately 200°C/400°F in an IGCC configuration), scrubs out the solid particulate and removes chlorine and some NH3. The scrubbing water also absorbs a minor amount of carbon dioxide. The materials of construction of these wet scrubbing systems need to take into consideration the potentially acidic nature of the water (from the chlorine, and carbon dioxide). The liquid effluent from this system contains unconverted coal (char), coal ash that did not form a slag, chlorine, and NH3 compounds. This liquid effluent is further processed in a clarifier to concentrate the char and ash particles in a stream known as black water and a cleaner stream known as gray water. The gray water is recycled to the scrubber and/or the gasifier and the black water is further processed in a wastewater treatment system. As an enhancement to the efficiency of the overall IGCC plant, the carbon-rich
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solids in the black water can be removed and recycled to the gasifier. In a slurry gasifier, such as the GE technology, this is accomplished by returning these solids to the coal slurry. In a dry feed gasifier, such as a Siemens gasifier, these solids must be dried to be used with the coal feed.
10.2.2 Dry particulate removal The alternative approach is to remove the solids in a dry state, and subsequently scrub the syngas with water to remove the chlorine. The E-Gas technology uses hightemperature metallic barrier-type filters operating at approximately 400°C (750°F) to remove the unconverted char and coal ash from the syngas stream. This stream of solids is then returned to the high-temperature slagging stage of the E-Gas gasifier to convert the carbon to syngas and the ash to slag. The particulate free syngas is then scrubbed with water to remove chlorine. This is an important step, since the metallurgy of the downstream equipment is affected negatively by chlorine. The chlorine, in the form of hydrochloric acid, can both deactivate catalysts and attack the materials of construction of equipment when the syngas is cooled further, to provide the appropriate temperature for mercury removal and acid gas removal (approximately 38°C/100°F). Depending on the amount of the condensed acid and the materials of construction, the deterioration of the equipment can be slow or rapid. Capturing the solids in a dry state and immediately recycling to the gasifier removes the venture scrubber, the attendant gray water/black water system, and the equipment to capture the wet char for recycling. The high-temperature particulate filters can be either metallic or ceramic (Knight et al., 2014). The design of the filter system must incorporate safeguards to address broken filters that would allow particulate matter to get into the remainder of the cleanup train and require immediate maintenance. The wet scrubbing system typically does not encounter this type of particulate breakthrough.
10.3 Contaminants removal from biomass-based IGCC systems Biomass-based IGCCs have somewhat different cleanup systems compared to coalbased IGCCs in that the removal of tars must be addressed. Two approaches to tar removal are available. One is the addition of a higher-temperature step after gasification to crack the tars to shorter-chain hydrocarbons that are compatible with the combustion turbine. The second approach is a specially designed scrubbing system. However, biomass IGCCs still require removal of particulates and the chemical contaminants. As with a coal-based IGCC, the specific cleanup system between the gasifier and the combustion turbine must take into consideration the specific contaminates in the biomass feedstock. Sulfur levels in most biomass are low and, as such, downstream sulfur removal may not be required. However, they still require the removal of particulates and the chemical contaminates. The following discussion is based on a woody feedstock and a fluidized bed-type of gasifier. In these units, cyclones are used for initial particulate capture and char
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recycle to enhance carbon conversion and efficiency of the system. Biomass-based IGCCs typically operate at temperatures that are below the slagging temperature of the feedstock. Thus, the ash components are not slagged. In addition, these systems operate at pressures that are lower than the operational pressures of combustion turbines, and compression of the syngas is required at a point in the syngas processing train. As previously noted, with the lower operating temperatures (typically in the 820°C/1500°F range), the syngas contains tars that need to be removed prior to the compressions step where tars would condense and cause maintenance and availability problems. The removal of the tars is necessary to prevent fouling of compressors and combustion equipment. In the case of a high-pressure biomass gasifier (greater than 30 bar pressure), where no compression step were needed, the fuel requirements of the combustion turbines (no condensable hydrocarbons at the combustor inlet temperature) would still require tar removal. Several approaches to tar removal have been suggested for biomass-based systems. One approach increases the temperature of the syngas to 990°C (1800°F) or higher to crack the tars to shorter chain hydrocarbons. This can be accomplished by passing the syngas through a high-temperature sand bed (Paisley et al., 2007), adding direct oxygen to raise the syngas temperature in the freeboard of the fluidized gasifier, adding a catalytic tar converter (Knight et al., 2014), or a natural gas-based hot oxygen burner in a separate partial oxidation reactor. The design needs to take into consideration the temperature at which the biomass ash creates a slag (typically approximately 1100°C/2000°F, although some biomass materials have lower slagging temperatures). Raising the temperature into the ash slagging range may destroy all of the tars; however, the liquid ash needs to be handled. What the non-slagging systems have in common is that they do not necessarily destroy all of the tars completely (some light shorterchain tars may remain, such as benzene and naphthalene). These tar-cracking units are typically followed by wet scrubbers. The wet scrubbers serve to remove chlorine, NH3, some of the benzene, and any remaining particles. However, naphthalene can condense to a solid and leave the scrubber and an additional particulate filter may be required. The short chain tars that remain in the syngas are burned in the combustion turbine. The use of the catalytic tar converter requires a high-temperature barrier filter prior to the catalytic converter to remove particulate matter to protect the catalyst from fouling. Some designs do not incorporate a high-temperature unit and instead use a multiphase or multiple scrubbers. These scrubbers utilize a combination of oil-based scrubbers (to remove the non-water soluble tars, for example) (Konemann and Zwart, 2007) followed by water-based scrubber systems for chlorine and partial NH3 removal. In either case, naphthalene, which is a highly refractory hydrocarbon, is difficult to destroy or remove completely. Although a vapor, at high temperatures this material becomes solid at lower temperatures and is typically filtered out prior to compression.
10.4 Efficiency of IGCC systems as related to WS/PR As discussed in other chapters, for example syngas cooling in Chapter 9, Syngas cooling in IGCC systems, IGCC systems incorporate several means of heat recovery
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to enhance the efficiency of the overall process. However, overall carbon conversion is a key metric in enhancing overall process efficiency. A secondary consideration is any change in power consumption to achieve the recycle of the unconverted carbon. The gasification systems usually do not fully convert all of the carbon to syngas on the first pass through the gasifier and recycling of this unconverted carbon can enhance the efficiency of conversion of the energy in the solid fuel to power by approximately 2 to 4%. As discussed above, both the wet scrubbing and dry particulate approach can recycle unconverted carbon to the gasifier to enhance carbon conversion. The dry particulate removal approach (barrier filters and cyclones) maximizes the carbon conversion by approaching nearly complete carbon recycle, while the wet scrubbing approach tends to lose some carbon in the water processing process. Typically, approximately 70% of the unconverted carbon from the water system is recovered. A secondary item is the moisture content of the recycled material. The drier the material, the less energy required to gasify the recycled carbon. Overall, the dry particulate approach has an advantage in efficiency enhancement over the wet scrubbing approach. In biomass-based IGCCs, unreacted carbon can also be recycled back to the gasifier as a dry particulate (from cyclones or barrier filters), and as captured tar from the scrubbers. Each system must be investigated to determine the best approach to accomplish the enhanced efficiency goal.
10.5 New technologies The capture of carbon dioxide is a feature that was not incorporated in IGCC units until recently. IGCC systems built in the 1990s, such as Wabash River (DOE Topical Report 20, September 2000), and Polk County (DOE Topical Report 19, July 2000) in the US and Buggenum (EPRI Report, 2007), and Puertollano (Radtke, HeinritzAdrain, Hooper and Richards, 2008) in Europe did not include carbon capture and had simpler syngas cleanup and conversion subsystems. The newer (2014) Edwardsport IGCC (Zupan, 2009) also did not capture carbon dioxide (although it is stated to be carbon capture ready). However, the Kemper County (Southern Company, 2011) under construction in 2015 has partial carbon capture (65%) and the Texas Clean Coal Project (NETL Technical Note, 2014) (under development in 2015) has a 90% carbon capture design. The addition of maximum carbon dioxide capture changes the design of the syngas conversion and cleanup train, by incorporating water-gas-shift reactors (which replace the COS hydrolysis reactor in Fig. 10.1) and a more robust acid gas removal process (sulfur and carbon dioxide). In either case, the first unit operation after the syngas exits the gasification unit is the WS/PR. High-temperature plasma units (see Chapter:Municipal wastes and other potential fuels for use in IGCC systems) are being developed for municipal waste and hazardous waste feedstocks (a large-scale unit is under construction at Teeside in the United Kingdom) are similar to slagging coal gasifiers in their WS/PR units. The plasma systems typically operate at above the slagging temperature of the biomass and do not produce tars.
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The introduction of new technologies into IGCC systems can influence WS/PR in two separate regimes. Improvements in the capability of barrier filters to operate at higher temperatures (currently available in 2016 to 730°C/1350°F) widens the flexibility of design engineers to improve the overall efficiency of systems by allowing for high-temperature heat recovery without the potential fouling of the heat exchanger or downstream catalytic converters. Higher temperature particulate filters are currently available (see Pall) that can have an impact on the efficiencies of biomass-based IGCCs. The use of catalytic tar crackers requires a particulate-free syngas. Designs that incorporate a high-temperature filter (greater than 820°C/1500°F) can eliminate the need to cool the syngas prior to entering the tar cracker, and minimize or eliminate the need to add an oxidant to raise the temperature of the syngas to enable the catalyst to operate effectively. In addition to filtering the syngas prior to a high-temperature heat recovery, such filters tend to reduce fouling of the heat exchanger and can result in better availability. Carbon capture or the removal of carbon dioxide from the syngas in an IGCC does not change the basic design of the WS/PR unit operation. The differences are downstream of the WS/PR operation, and the requirements for the removal of the bad actors addressed by WS/PR remains the same. Traditionally, sulfur removal has been incorporated into IGCC systems at the cold end of the process after the syngas has been cleaned of mercury (at approximately 38°C/100°F). The systems commercially available (chemical and physical absorbents) provide better removal of sulfur compounds (primarily H2S) at low temperatures. Recently, RTI developed a hot sulfur removal process, which has been piloted at the Tampa Electric IGCC since 2014. This system contacts the syngas with a solid adsorbent, removing the sulfur to levels of approximately 5 parts per million. The current design has this hot sulfur removal system after the particulate removal device. For the Tampa Electric unit, this is after the wet scrubber. The placement of this unit does not affect the current designs of the WS/PR systems; however, implementation may require additional particulate removal downstream to protect the combustion turbine form carryover of the solid sorbent.
References Department of Energy Topical Report No. 19, 2000. The Tampa electric integrated gasification combined cycle project, an update, July 2000. Department of Energy Topical Report No. 20, 2000. the Wabash River coal gasification repowering project, an update, September 2000. EPRI Report, 2007. Integrated gasification combined cycle (IGCC) design considerations for high avalibility, volume I: lessons from existing operations, technical update March 2007. Knight, R., Udengaard, N., Bryan, B., Patel, J., Jensen, J., Jokela, P., et al., 2014. Woody biomass to gasoline: pilot biorefinery test results, Symposium on Thermal and Catalytic Eciences for Biofuels and Biomass Products September 2014. Konemann, J.-W., Zwart, R., 2007. Olga tar removal, 4 MWt commercial demonstration biomass gasification in France, Gasification Technologies conference 2007.
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NETL Technical Note, 2014. Summit Texas clean energy < LLC: Texas clean energy project; Pre-Combustion CO2 Capture and Sequestration 2014. Paisley, M., Corley, R., Dayton, D., 2007. Advanced biomass gasification for the economical productin of power, fuels and hydrogen-implementation in montgomery New York, 15th European Biomass Conference and Exposition Berlin 2007. Radtke, K., Heinritz-Adrain, M., Hooper, M., Richards, B., 2008. 10 years operating experience at ELCOGAS IGCC, Puertollano, Spain, Gasification Technologies Conference 2008. Southern Company, 2011. CO2 capture at the Kemper County IGCC project, NETL CO2 Capture Technology Meeting 2011. Zupan, D., 2009. Edwardsport IGCC moving forward, Gasification Technologies Conference 2009.
Biography
Dr. Kosstrin is a Managing Director in Leidos Engineering, LLC (Leidos), and is a Leidos technical fellow. Dr. Kosstrin has over 40 years of experience in the development, demonstration, and evaluation of processes to enhance environmental performance, produce alternative fuels, and provide alternative sources of power generation. He has been involved in the technical development, feasibility analysis and/or independent review of a variety of gasification technologies using a wide range of feedstocks including coal, biomass and wastes. He is familiar with fixed bed, fluidized bed and entrained flow systems utilizing coal and/or biomass, including municipal solid waste and refuse-derived fuel (RDF). These systems were designed to produce either low Btu gas, medium Btu gas or synthesis gas which was used to fire boilers, gas turbines or provide a feedstock for chemicals (hydrogen, ammonia, urea, methanol, etc.) and fuels (diesel, gasoline, ethanol, and crude-type oils).