Clean coal conversion processes progress and challenges

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1 / Journal Homepage / Table of Contents for this issue PERSPECTIVE Energy & Environmental Science Clean coal conversion processes progress and challenges Fanxing Li and Liang-Shih Fan* Received 30th May 2008, Accepted 11th July 2008 First published as an Advance Article on the web 30th July 2008 DOI: /b809218b Downloaded on 06 October 2012 Although the processing of coal is an ancient problem and has been practiced for centuries, the constraints posed on today s coal conversion processes are unprecedented, and utmost innovations are required for finding the solution to the problem. With a strong demand for an affordable energy supply which is compounded by the urgent need for aco 2 emission control, the clean and efficient utilization of coal presents both a challenge and an opportunity to the current global R&D efforts in this area. This paper provides a historical perspective on the utilization of coal as an energy source as well as describing the progress and challenges and the future prospect of clean coal conversion processes. It provides background on the historical utilization of coal as an energy source, along with particular emphasis on the constraints in current coal conversion technologies. It addresses the energy conversion efficiencies for current coal combustion and gasification processes and for the membrane and looping based novel processes which are currently under development at various stages of testing. The control technologies for pollutants including CO 2 in flue gas or syngas are also discussed. The coal conversion process efficiencies under a CO 2 constrained environment are illustrated based on data and ASPEN Plus Ò simulations. The challenges for future R&D efforts in novel coal conversion process development are also presented. 1. Background Energy and global warming are two intertwined issues of significant magnitude in the modern era. With oil prices rising above $120/barrel and atmospheric CO 2 levels increasing at a rate greater than 1.5 ppm each year, 1 3 an urgent need exists for development of clean and cost effective energy conversion processes. Renewable energy sources such as hydro, wind, solar, geothermal, and biomass will help reduce anthropogenic CO 2 emissions by mitigating fossil fuel consumption. However, with the high cost, geological constraints, and intermittency issues, Department of Chemical and Biomolecular Engineering, The Ohio State University, 140 West 19th Avenue, Columbus, Ohio, 43210, USA. Fan.1@osu.edu; Fax: ; Tel: renewable energy is not likely to contribute to a significant share of the total energy demands in the foreseeable future. 4,5 Similarly, concerns over plant safety and radioactive waste disposal will impede the wide utilization of nuclear power. 6 Thus, despite high crude oil and natural gas prices, fossil fuels will continue to provide more than 85% of the overall world energy consumption for the next several decades. 7 US DOE studies indicate that the consumption of coal as an energy resource is more responsive to crude oil price fluctuations than renewable energy sources in the near term, and coal could regain its role as a major energy source by Fig. 1 shows the impact of oil prices on the consumption of coal and other energy sources. The attractiveness of coal lies in its abundant reserves and stable prices when compared to both oil and natural gas. Without the implementation of pollution control, enhanced coal usage will result in serious environmental impacts since coal F: Li Fanxing Li received his B.S. degree in 2001 and his M.S. degree in 2004 in Chemical Engineering from Tsinghua University. He is a graduate research associate in the Department of Chemical and Biomolecular Engineering at The Ohio State University. He is currently working on a number of projects with Professor L. S. Fan including energy and environmental reaction engineering and clean coal conversion processes. L: S: Fan L. S. Fan is Distinguished University Professor and C. John Easton Professor in Engineering in the Department of Chemical and Biomolecular Engineering at The Ohio State University. His expertise is in fluidization and multiphase flow, powder technology and energy and environmental reaction engineering. He is a member of the U. S. National Academy of Engineering, and an Academician of the Academia Sinica. 248 Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

2 Downloaded on 06 October 2012 Fig. 1 (a) Three different (long term) world oil price scenarios predicted by EIA; (b) world energy consumption in 2030 based on energy sources. 7 contains various contaminants and is the most carbon-intensive energy source. Of major global concern is the fact that the combustion of fossil fuels releases 27 gigatons of CO 2 each year. 7,8 With increasing coal consumption, the anthropogenic CO 2 emission rate may reach well over 40 gigatons per year within the next two decades in the absence of effective CO 2 mitigation techniques. 7,8 Therefore, modern coal conversion technologies need to be able to efficiently convert coal into useful products while controlling the CO 2 emission. Unlike crude oil, which is primarily used as transportation fuels, coal is primarily used as a stationary source for electricity generation. Thus, CO 2 capture from coal can be more readily implemented. This article addresses clean coal conversion technologies from the process viewpoint. Coal combustion processes are first discussed along with the various options for pollutant control and CO 2 capture. It is then followed by an overview of coal gasification processes. Advanced membrane and chemical looping based systems using gaseous feedstock as well as advanced direct coal chemical looping systems are illustrated. These advanced technologies that yield high energy conversion efficiencies are at various stages of development and are potentially deployable in the near or intermediate term. 2. Coal combustion processes Archeological evidence indicates that humans have been burning coal for at least 4000 years Throughout history, coal has been used to generate heat and to smelt metals. However, it was not until the 18 th century that coal started to play an indispensible role in the economy. As an important fuel that propelled the industrial revolution, 12,13 coal has been widely used since the 1700s to drive steam engines, in the operation of blast furnaces for metal production, in the production of cement, and in the generation of town gas for lighting and cooking. Since the late 19 th century, coal has been used to power utility boilers for electricity generation. 14 Although its dominance as an energy source was replaced by crude oil in the 1950s, coal is still the single most important fuel for electricity generation today, accounting for 40% of the electricity generated worldwide. 7 The dominance of coal in electricity generation is expected to continue well into the 21 st century. Fig. 2 Simplified schematic diagram of a Pulverized Coal (PC) combustion process for power generation. Presently, pulverized coal (PC) fired power plants account for more than 90% of the electricity generated from coal. 15 The schematic flow diagram of a PC power plant is illustrated in Fig. 2. In a PC power plant, coal is first pulverized into fine powder with over 70% of the particles smaller than 74 mm (200 mesh). The pulverized coal powder is then combusted in the boiler with the presence of 20% excess air. 14 The heat of combustion is used to generate high pressure, high temperature steam that drives the steam turbine system based on a regenerative Rankine cycle for electricity generation. Although the underlying concept is quite simple, the following challenges need to be addressed for modern PC power plants: enhancement of energy conversion efficiency; effective control of hazardous pollutants emission; and CO 2 capture (and sequestration). 2.1 Energy efficiency improvement An increase in the combustion process efficiency leads to reduced coal consumption and hence, a potential cost reduction for electricity generation. The first generation coal fired power plants constructed in the early 1900s converted only 8% of the chemical energy in coal into electricity (based on the higher heating value, HHV). 16 Since then, a significant improvement in plant efficiencies has been made. Thermodynamic principles require higher steam pressures and temperatures for a higher plant efficiency. The corrosion resistance of the materials for boiler tubes, however, constrains the maximum pressure and temperature of This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

3 Downloaded on 06 October 2012 the steam. Most of the PC power plants currently under operation utilize sub-critical PC (Sub-CPC) boilers which produce steam with pressures up to 22 MPa and temperatures around 550 C. The energy conversion efficiencies of traditional Sub-CPC power plants typically range from 33% to 37% (HHV). 17 With an increase in the steam pressure, supercritical PC (SCPC) power plants were first introduced in the early 1960s in the US. 16 Supercritical power plants involve steam with a typical pressure of 24.3 MPa and temperatures up to 565 C, leading to a plant efficiency of 37 to 40%. 17 Many supercritical power plants were constructed in the 1960s and 70s in the US. However, due to the low reliability of the boiler materials, the further application of the SCPC technology was essentially halted in the US in the early 1980s. The development of high performance super alloys coupled with increasing environmental concerns and the rising cost of coal during the last two decades has stimulated the revival of supercritical technology, especially in Europe and Japan, leading to the reduction of subcritical boilers in newly installed fleets. Recent advancements in coal combustion technologies are highlighted by the generation of ultra-supercritical (USCPC) steam conditions that can provide even higher process efficiencies. The ultra-supercritical condition refers to the operating steam cycle conditions above 565 C (>1050 F). 17 The pressure and temperature of the steam generated from existing ultrasupercritical power plants can reach 32 MPa and 610 C, corresponding to an energy conversion efficiency of over 43%. 17,18 The global on-going R&D activities on PC boilers focus on the development of super alloys that can sustain steam pressures up to 38.5 MPa and temperatures as high as 720 C. It is expected that a plant efficiency of over 46% can be achieved under such conditions Other efforts in ultra-supercritical technology include minimizing the usage of super alloys, improving the welding technique, and optimizing the boiler structure design to minimize the steam line to steam turbine. 18 Besides PC boilers, Fluidized Bed Combustors (FBC) using either turbulent fluidized beds or circulating fluidized beds are also being used for steam and power generation world wide. In these processes, limestone is often injected to capture SO x formed during coal combustion. Compared to PC boilers, the FBC has lower SO x and NO x emissions. 20,21 Furthermore, it has superior fuel flexibility. 22 Most commercial FBC plants operate under atmospheric pressures, with energy conversion efficiencies similar to subcritical PC power plants. Higher efficiencies can be achieved by operating the FBC at elevated pressures The Pressurized Fluidized Bed Combustor (PFBC) generates a high temperature, high pressure exhaust gas stream which drives a gas turbine steam turbine combined cycle system for power generation. In an advanced PFBC (APFBC) configuration, fuel gas is generated from coal via particle oxidation and pyrolysis. The fuel gas is combusted to drive a gas turbine (topping cycle). Such a process has the potential to achieve an energy conversion efficiency of over 46%. 23 To date, the PFBC demonstrations have shown relatively low plant availability. In addition, the capital investment for PFBC is higher than PC power plants with a similar efficiency. 25 Other potential challenges to the PFBC technology include scale-up, high temperature particulates/ alkali/sulfur removal for gas turbine operation, and mercury removal from the flue gas. 22,26 Table 1 compares the performance of different coal combustion technologies. The energy penalties Table 1 Energy conversion efficiencies (HHV) of various coal combustion technologies and energy penalty for CO 2 capture using MEA 17,27 32 Technology Sub-CPC SCPC USCPC AFBC Base case efficiency (%) HHV for the 90% CO 2 capture using a retrofit monoethanolamine (MEA) scrubber as discussed in Section 2.3 are also shown in Table Flue gas pollutant control methods Modern coal combustion power plants need to be able to capture environmentally hazardous pollutants released from coal combustion. Such pollutants include sulfur oxides, nitrogen oxides, fine particulates, and trace heavy metals such as mercury, selenium, and arsenic. Methods for capturing these contaminants from the flue gas streams abound. The challenges, however, lie in the efficient and cost effective removal of these contaminants. The traditional method for SO x removal utilizes wet scrubbers with alkaline slurries. The wet scrubber is effective; however, it is costly and yields wet scrubbing wastes that must be disposed of. Alternative methods have included more cost effective lime spray drying and dry-sorbent duct-injection. The lime spray drying method employs slurry alkaline spray yielding scrubbing wastes in solid form, easing the waste handling. The dry-sorbent ductinjection employs a dry alkaline sorbent for direct in-duct injection, circumventing the use of the scrubber. The recent pilot testing using re-engineered limestone sorbents of high reactivity yields a sorbent sulfation efficiency of over 90%, compared to under 70% with ordinary limestone sorbent, indicating a viability of the dry-sorbent duct-injection method with very active sorbents The NO x is commonly removed by selective catalytic reduction (SCR). Other methods that can be employed include low NO x burner and O 3 oxidation. The recent pilot testing of the CARBONO x process using coal char impregnated with alkaline metal revealed a high NO x removal efficiency at low flue gas temperatures. 36 The trace heavy metals such as mercury, selenium, and arsenic can be removed by calcium based sorbent and/or activated carbon. 33,37 The techniques to control the flue gas pollutants indicated above are well-developed. An effective capture (and sequestration) of CO 2, an important green house gas (GHG) that accounts for 64% of the enhanced green house effect 38 is, however, a challenging task. 2.3 CO 2 capture systems PFBC/ APFBC MEA retrofit b 30 b derating (%) a a Percentage decrease in energy conversion efficiency when a retrofit MEA system is used to capture 90% of the CO 2 in the flue gas. b Estimated based on ASPEN simulation by authors. Coal-fired power plants are responsible for nearly a third of all anthropogenic CO 2 emissions. 39 Therefore, cost-effective carbon 250 Energy Environ. 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4 capture technologies for these plants play an important role in CO 2 mitigation. CO 2 represents 15% of the atmospheric pressure flue gas stream from coal combustion power plant (dry basis). Low CO 2 partial pressures combined with the extremely high flue gas generation rate make the CO 2 capture from PC power plants an energy consuming step. An ideal CO 2 capture technology would incorporate effective process integration schemes while minimizing the parasitic energy requirement for CO 2 separation. The existing CO 2 capture techniques from PC power plants include the well-established MEA scrubbing technology. Fig. 3a shows the schematic diagram of the MEA scrubbing process which indicates the key stream conditions of the process In this process, the flue gas is first cooled down to 40 C before entering the absorber where fresh amine is used to absorb CO 2 in the flue gas stream. The spent amine solution with a high CO 2 concentration is then regenerated in the stripper under a higher temperature ( C), and CO 2 is then recovered at low pressure ( MPa). A large amount of high temperature steam is required to strip the CO 2 in the regeneration step. 42,43 Therefore, a significant amount of energy will be consumed for steam generation and the subsequent CO 2 compression step. It is estimated that the CO 2 capture (separation and compression) using amine scrubbing will reduce the power generated from the entire plant by as much as 42%, 29 which amounts to 70 80% of the total cost in the overall three-fold carbon management steps, i.e. carbon capture, transportation, and sequestration. 44,45 As a result, a process that can reduce the energy consumption in the CO 2 capture step will be vital for CO 2 management in coal fired power plants. The chilled ammonia process, illustrated in Fig. 3b, is another solvent based CO 2 capture technology where ammonia carbonate and bicarbonate slurries are used to capture the CO 2 in the flue gas stream at 0 10 C and atmospheric pressure. The CO 2 rich solvent is then regenerated at C and 2 4 MPa. The capability to regenerate CO 2 at elevated pressures reduces the energy consumption for CO 2 compression. Based on the studies by the Electric Power Research Institute (EPRI) and ALSTOM, the overall energy penalty for CO 2 capture is estimated to be lower than 16% when the chilled ammonia process is used. 46,47 A 5 MW th (megawatts thermal) equivalent chilled ammonia process demonstration plant, jointly supported by ALSTOM and EPRI, is currently under construction at We Energies Pleasant Prairie Power Plant in Wisconsin. 48 American Electric Power (AEP) is also planning to demonstrate the chilled ammonia process at the 20 MWe (megawatts electricity) scale, starting in 2009, before building a 200 MWe commercial level chilled ammonia retrofit system in Similar to solvent based CO 2 scrubbing techniques, high temperature sorbents such as limestone, potassium carbonates, lithium silicates, and sodium carbonates can be used to capture CO 2 in the flue gas at elevated temperatures. 50,51 With better heat integration, these strategies can potentially decrease the energy consumption in the CO 2 separation step. One scheme for heat integration is based on the calcium based carbonation calcination reaction (CCR) process which uses hydrated lime, and natural or re-engineered limestone sorbents at C for CO 2 separation. 52 Fig. 4 delineates the heat integration strategies for retrofitting the CCR process to an existing PC power plant. In the CCR process, both CO 2 and SO 2 in the flue gas are captured by the CaO sorbent in the carbonator operated at 650 C, forming CaCO 3 and CaSO 3 /CaSO 4 The carbonated sorbent, CaCO 3, is then regenerated to calcium oxide (CaO) sorbent in the calciner at C, yielding a pure CO 2 stream. The sulfated sorbent and fly ashes are removed from the system by means of a purge stream. Due to an optimized energy management scheme, the CCR process consumes 15 22% of the energy generated in the plant. 53,54 The process is being demonstrated in a 120 kw th (kilowatts thermal) pilot plant located at The Ohio State University (OSU). A similar process is being demonstrated at CANMET Energy Technology Center in Canada. 55 Studies or reviews on the post combustion CO 2 capture using solid sorbents can be found in other literature sources In addition to the absorption adsorption based technologies, oxy-fuel combustion technology provides another means for carbon management in coal fired power plants. In this technology, pure oxygen instead of air is used for coal combustion. As a result, a concentrated CO 2 stream is generated, avoiding the need for CO 2 separation. However, the energy-consuming cryogenic air separation step will reduce the overall plant efficiency by 20 35%. 17,30,45,60 This process has been successfully demonstrated by the Babcock & Wilcox Company on a 1.5 MW th pilot scale PC unit. Demonstration on a 30 MW th unit is currently under way. The on-going pilot scale studies on oxy-fuel combustion include those carried out by ALSTOM, Foster- Wheeler, CANMET Energy Technology Center, Vattenfall, and Ishikawajima-Harima Heavy Industries (IHI). 61 To generalize, a number of retrofit systems under different stages of development can be used to capture CO 2 from existing power plants. Since PC power plants will continue to provide Fig. 3 Conceptual schematic of (a) the MEA scrubbing technology for CO 2 separation; (b) the Chilled Ammonia technology for CO 2 separation. This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

5 Downloaded on 06 October 2012 Fig. 4 Conceptual schematic of Carbonation Calcination Reaction (CCR) process integration in a 300 MWe coal fired power plant depicting heat integration strategies. a significant portion of the electricity needs well into the 21 st century, 7 these CO 2 capture systems are essential to mitigate the environmental impact from coal burning. In general, however, CO 2 capture and compression from a coal combustion flue gas is costly and energy intensive. A more promising approach to reduce the overall carbon footprint of a coal based plant is to adopt coal conversion processes that are intrinsically advantageous from a carbon management and energy conversion standpoint. Among the various options, coal gasification described below offers such attraction. 3. Coal gasification processes For years, the commercial efforts on clean coal processes have been centered on coal combustion for power generation. However, new process developments with a focus on higher energy conversion efficiencies for electricity generation as well as variability in product formation have generated considerable interest. Coal gasification schemes can provide a variety of products e.g. hydrogen, liquid fuels and chemicals besides electricity. Further, gasification is a preferred scheme from a pollutant and carbon management viewpoint. 3.1 Overview (WGS) reaction can be 80 times higher than that in the PC boiler flue gas (dry basis). The significantly reduced gas flow rate and increased gas partial pressures make the pollutant and CO 2 control an easier task for gasification processes when compared to coal combustion processes. Fig. 5 shows the modern coal gasification process that generates a variety of products. In the coal gasification process, coal first reacts with oxygen (and steam) to produce raw syngas. The raw syngas, with pollutants such as particulates, H 2 S, COS, HCl, ammonia, and mercury, is purified before it is sent to a gas turbine steam turbine combined cycle system for electricity generation. This syngas route is known as the Integrated Gasification Combined Cycle (IGCC). The electricity generation efficiency of the IGCC process can be higher than 45% (HHV) without CO 2 capture. 62,64 In a carbon constrained scenario, however, the CO in the syngas stream will be further converted to CO 2 and H 2 through the water gas shift (WGS) reaction: CO + H 2 O / CO 2 +H 2 (1) Thus, the resulting gas stream contains a high CO 2 concentration (up to 40% by volume on the dry basis). The CO 2 (and H 2 S) can be captured using either chemical absorption based Compared to combustion, coal gasification is relatively new. Commercial gasification processes date back to the late 18 th century when coal was converted into town gas for lighting and cooking. Since the 1920s, the gasification process has been used to produce chemicals and fuels. 62 Unlike traditional combustion processes which fully oxidize carbonaceous fuels to generate heat, modern coal gasifiers convert coal into syngas via partial oxidation reactions with oxygen or with steam and oxygen under elevated pressures. 14,62 The high pressure syngas stream, undiluted by N 2 in the air, has a much lower volumetric flow rate when compared to that of the flue gas from coal-fired power plants. As a result, the partial pressure of the contaminants is significantly increased. For instance, the volumetric flow rate of syngas generated from a dry feed, oxygen blown gasifier can be two orders of magnitude lower than that from a PC boiler with similar coal processing capacity (dry basis). Meanwhile, the partial pressure of CO 2 in the syngas after the water gas shift Fig. 5 Schematic diagram of coal gasification processes Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

6 acid gas removal processes such as monoethanolamine (MEA) or methyldiethanolamine (MDEA) described in Section 2.3 or physical absorption based processes such as Selexol and Rectisol, yielding concentrated H The H 2 can be used to generate electricity through a combined cycle system with minimal carbon emissions. Alternatively, the H 2 stream can be further purified using pressure swing adsorption (PSA) units. The resulting high-purity H 2 can be used for fuel cell applications. Besides electricity and H 2 generation, syngas can also be converted to chemicals and liquid fuels such as diesel and naphtha through the Fischer Tropsch (F T) reactions, which can be represented by: (2n + 1)H 2 + nco / C n H 2n +2 + nh 2 O (2) The process that converts coal to liquid fuels via coal gasification and F T synthesis is also referred to as the indirect coalto-liquid (CTL) process. Unlike the indirect CTL process, the direct CTL process liquefies coal directly by reacting it with hydrogen at elevated pressure. 69,70 The direct CTL process can achieve a high liquid fuel yield close to 3 barrel liquids per ton of coal when coal is also used as the hydrogen source. 71 The pilot demonstrations of CTL processes took place during the 1970s to 1990s and included the H Coal process (by Hydrocarbon Research Inc.) and the Integrated Two-Stage Liquefaction process (by Lummus Company). 71 The first commercial direct CTL process plant is being built in Inner Mongolia, China by Shenhua Group Corporation. The production cost for the direct CTL process is higher than for the indirect CTL process. 71 Processing of coal using the gasification approach has the advantages in product versatility and pollutant controllability when compared to the combustion approach. However, gasification is more capital intensive. A study conducted in 2001 indicated that an IGCC system required 6 10% more capital investment when compared to an ultra-supercritical PC plant. 72 Both plants have similar energy conversion efficiencies. Although CO 2 capture from the gasification process is easier when compared to a PC plant, the CO 2 capture, nevertheless, represents an energy and capital intensive step in the process. The CO 2 capture can derate the energy conversion efficiency of the IGCC system by 13 24%, increasing the cost of electricity by 25 45%. 28,31,73 75 Other issues related to gasification include large parasitic energy consumption in the WGS step due to the need for the excessive steam as well as the temperature and pressure swing requirement in the process for sulfur and mercury removal. Gasification, like other technologies, has undergone evolution since its inception. Over the years, different types of gasifiers have been developed which provide a higher carbon conversion, cold gas and thermal efficiencies, and flexibility in the type of fuel used. These gasifier types include the fixed/moving bed gasifier, fluidized-bed gasifier, entrained-flow gasifier, and transport gasifier. 62 Most of the modern gasifiers adopt an entrained-flow design due to better fuel flexibility, carbon conversions, and syngas quality. 76 Other ongoing research activities include the use of an Ion Transport Membrane (ITM) instead of the cryogenic separation technique to reduce the energy consumption of the air separation unit (ASU), 77,78 the increase in the gas turbine inlet temperature to increase the combined cycle efficiency, and the development of a warm and hot gas clean up system to efficiently remove pollutants such as particulates, sulfur and mercury As there is a large degree of operational variation in individual units and in an integrated process system, optimization of the gasification process requires elaborate consideration of all the viable process configurations. For this purpose, simulation software such as ASPEN Plus Ò is often used to aid in the analysis of the process configurations under various process variables. In the following section, a case study is presented which illustrates the energy conversion efficiency for an IGCC system with CO 2 capture through simulation using the ASPENÒ plus software. 3.2 ASPEN analysis on IGCC system with CO 2 capture a case study Aspen Plus Ò has been widely used to simulate energy conversion systems. 41,82 87 Based on appropriate assumptions and relevant experimental data of the individual units, the ASPEN Plus Ò software can assist in the evaluation of the process performance, and in the optimization of the process configuration. The IGCC system illustrated in this case study uses a GE/Texaco slurryfeed, entrained flow gasifier with total water quench syngas cooler. The flow diagram of the process is shown in Fig. 6. In this process, coal is first pulverized and mixed with water to form coal slurry. The coal slurry is then pressurized and introduced to the gasifier to be partially oxidized at 1500 C and 3.04 MPa (30 atm). The high temperature raw syngas after gasification is then quenched to 250 C with water. The quenching step solidifies the ash. Moreover, most of the NH 3 and HCl in the syngas are removed during this step. After quenching, the syngas is sent to a Venturi scrubber for further particulate removal. The particulate-free syngas, saturated with Fig. 6 IGCC process with CO 2 capture. This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

7 steam, is then introduced to the sour WGS unit. The syngas exiting the WGS unit contains mainly H 2 and CO 2 with small amount of CO, H 2 S, and mercury. This gas stream is then cooled down to 40 C and passed through an activated carbon bed for mercury removal. The CO 2 and H 2 S in the syngas are then removed using an MDEA unit, resulting in a concentrated hydrogen stream with small amounts of CO 2 and CO. The hydrogen rich gas stream is then compressed, preheated, and combusted in a combined cycle system for power generation. The combined cycle system consists of a gas turbine with an inlet firing temperature of 1430 C and a two stage steam turbine working at 550 C and 3.55 MPa (35 atm). The CO 2 obtained from the MDEA unit is compressed to MPa (150 atm) for sequestration. ASPEN modeling on coal conversion systems has been extensively discussed in various literature. 41,82,84 87 The following section briefly recapitulates the key steps to set up an ASPEN simulation model on the IGCC system described above. Prior to the simulation, a representative process flow sheet that contains all the major units is developed (Fig. 6). The appropriate assumptions for the simulation are then determined. The key assumptions are listed as follows: tonne/h of Illinois #6 coal is fed into the system (1000 MW in HHV) - Energy consumed for units such as acid gas removal are simulated based on performance data of the commercial units - The GE slurry feed gasifier has a carbon conversion of 99%, heat loss in the gasifier is 0.6% of the HHV of coal - A GE 7H gas turbine combined cycle system is used, all the exhaust gas is cooled down to 130 C before exiting the Heat Recovery Steam Generator (HRSG) - At least 90% of the CO 2 generated needs to be captured and compressed to MPa (150 atm) for sequestration - The mechanical efficiency of pressure changers is 1, whereas the isentropic efficiency is In order to accurately simulate the individual unit in the flow sheet, appropriate ASPEN Plus model(s) for each unit is determined. These models are listed in Table 2. Aspen Plus Ò has a comprehensive physical property database. Therefore, most of the chemical species involved in the process can be selected directly from the build-in database. The nonconventional components such as coal and ash can be specified conveniently using the general coal enthalpy modulus embedded in the ASPEN software. After the chemical species in the process are defined, the related physical property methods are selected according to the simulator s category. In this simulation, the global property method is PR BM, whereas local property methods are specified whenever necessary. The ASPEN model is finalized by establishing detailed operating parameters based on the operating conditions and design specifications of the individual unit. The units are then connected in the same arrangement as shown in the flow sheet. An appropriate convergence setting is determined to ensure accurate simulation results. Table 3 generalizes the simulation results of the IGCC system described above. The results shown in Table 3 can replicate the performance of existing IGCC power plants reported by Higman. 62 The ASPEN simulation can be effective for evaluating the performance of various coal conversion systems based on a common set of assumptions. 4. Advanced coal conversion processes Although with various improvements, as discussed in section 3, the efficiency of the conventional gasification systems is still limited due to the elaborate steps needed such as syngas cleaning and conversion, and gas separation and compression. Advanced coal conversion processes, which adopt novel process intensification strategies, streamline the conversion processes thereby yielding high energy conversion efficiency. Such techniques, which are currently at various stages of demonstration, encompass the membrane based approach and the chemical looping Table 3 Thermal energy input (MW th ) Coal Power Balance in a 1000 MW th IGCC plant with CO 2 capture Parasitic energy consumption (MWe) ASU CO 2 removal CO 2 compression Power generation (MWe) Gas turbine Steam turbine IP LP Net power (MWe) Table 2 ASPEN models for the key units in the IGCC process Unit operation Aspen Plus model Comments / specifications Air separation unit Sep Energy consumption of the ASU is based on specifications of commercial ASU/ compressors load. Coal decomposition Ryield Virtually decompose coal into various components (pre-requisite step for gasification modeling) Coal gasification Rgibbs Thermodynamic modeling of gasification Quench Flash2 Phase equilibrium calculation for cooling WGS Rstoic or Rgibbs To simulate conversion of WGS reaction based on either WGS design specifications or thermodynamics MDEA Sep or Radfrac Simulation of acid gas removal based on design specifications Burner Rgibbs or Rstoic Modeling of H 2 /syngas combustion step HRSG MHeatX Modeling of heat exchanging among multiple streams Gas compressors Compr or Mcompr Determines power consumption for gas compression Heater and cooler Heater Simulates heat exchange for syngas cooling and preheating Turbine Compr Calculates power produced from gas turbine and steam turbine 254 Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

8 based approach. Both approaches can process syngas derived from coal or any other carbonaceous feedstock. The chemical looping approach can also process coal or other carbonaceous feedstock directly. These approaches are elaborated below. 4.1 Membrane based gasification systems A membrane is a selective barrier between two phases. The molecules or small particles can transport from one phase to the other through the membrane. A H 2 or CO 2 selective membrane can be utilized in gasification processes to reduce the energy penalty for CO 2 capture and to enhance the hydrogen/electricity generation. The selective nature of a membrane can be attributed to one or more of the following mechanisms: (a) Knudson diffusion; (b) surface diffusion; (c) capillary condensation; (d) molecular sieving; (e) solution diffusion; and (f) facilitate transport. 88 As the smallest diatomic molecule, hydrogen can be separated from other gaseous species involved in the coal gasification process based on all the mechanisms stated above. On the other hand, most CO 2 selective membranes are based on either solution diffusion or facilitate transport mechanism since the CO 2 molecule is significantly larger. An amine based carrier is often used to facilitate the transportation of CO 2 from the retentate side to the permeate side. 88,89 As a result, a hydrogen selective membrane can be made of metallic, inorganic (ceramic), porous carbon, polymer, or hybrid materials while most of the CO 2 selective membranes for separating CO 2 from hydrogen are polymeric. The desirable features of a membrane include good permeability, selectivity, reliability, and tolerance to contaminants. For commercial applications in gasification processes, it should also be affordable, thermally stable, and durable. Of all the H 2 -selective membranes, metallic membranes and ceramic membranes are the most extensively studied The metallic H 2 -selective membranes generally have a very high selectivity and thermal stabilities. The potential candidates include palladium, platinum, tantalum, niobium, and vanadium. 88,90,93 Among these metals, Pd-based membranes, although relatively costly, have demonstrated the highest selectivity and good permeability and thermal stability. However, the presence of hydrogen at below 300 C can cause the embrittlement of the Pd-based membrane due to the Pd H phase transition. In order to reduce the membrane degradation as well as to reduce the cost, Pd-based membranes are often alloyed with Ag, Au, Y, Cu, or Se. These alloys are processed into a layer as thin as blow 1 mm and then doped on top of a porous ceramic or metallic support. 94,96 By alloying and supporting, the usage of Pd is minimized with increased physical strength of the membrane. 94 One major challenge to Pd-based membranes is that the presence of sulfur compounds such as H 2 S and COS under elevated temperatures can poison the Pd-based membranes. Recent studies indicate that alloying can increase the sulfur tolerance of the membrane. 97 However, a high sulfur content that is close to or beyond the thermodynamic limit for the formation of stable sulfides will nevertheless deactivate the membrane. 92 In addition, when ceramic support is used in the Pd-based metallic membrane, it will be necessary to resolve such issues as the mechanical strength of the support and the large difference in thermal expansion coefficients between the metallic membrane and the ceramic support. For metallic support, the challenge lies in the stability of the crystal structure due to inter-metallic diffusion. Therefore, desirable improvements in the Pd-based membrane for gasification applications include further reduction in cost coupled with increased durability, sulfur tolerance, and H 2 flux. Besides the Pd-based metallic membranes, non Pd-based alloys 98 and amorphous metals 93,99 are also under investigation with the prospect of developing less costly metallic membranes with satisfactory performance. Ceramic H 2 -selective membranes such as porous silica- and zeolite-based membranes represent another category of promising hydrogen separation materials Both membranes are microporous inorganic membranes comprised of a membrane layer, an intermediate layer, and a support. These membranes have several advantages when compared to metallic membranes including low cost, ease of fabrication, and less susceptibility to H 2 embrittlement. Moreover, very high hydrogen permeability can be achieved using an ultra-thin amorphous silica membrane. However, improvements that need to be made in these membranes include selectivity, defect reduction, thermochemical stability and operational stability. Table 4 generalizes the performances of existing H 2 -selective membranes as compared to the 2010 performance target set by the US DOE. Although zeolite-based membranes can be used to selectively remove CO 2 from other gases such as N 2 and CH 4 based on adsorption preference, 105,106 very limited studies have been performed on the separation of CO 2 from H 2 using such membranes. 51 Other attempts include those performed by Air Products and Chemical Inc. that use nanoporous carbon-based membranes to separate CO 2 from the tail gas of the Pressure Swing Adsorption (PSA) unit. 107,108 However, these membranes have relatively low CO 2 selectivity over H To date, most CO 2 -selective membranes for separating CO 2 from H 2 are polymeric membranes based on either solution diffusion mechanism or facilitate transport mechanism. 89, The challenges to the polymeric CO 2 -selective membranes include limited operating temperature and relatively low CO 2 /H 2 selectivity and flux. As mentioned in Section 3, the WGS reactor(s) and the CO 2 separation units consume a significant amount of parasitic energy for the coal to hydrogen process and IGCC process with CO 2 capture. The applications of the H 2 - or CO 2 -selective membranes in coal gasification systems for the intensification of the CO shift and hydrogen purification steps have been extensively studied during the last decade. Table 4 Performances of H 2 -selective membranes 88,92,101,103,104 Membrane type Metallic Porous ceramic DOE 2010 target T/ C Operating DP/MPa Selectivity > N/A Maximum flux/ SCFH ft 2 Sulfur tolerance/ppm Low > Metallic 20 Cost/USD ft 2 >1500 (Pt-based) This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

9 Downloaded on 06 October 2012 Several different configurations using different types of membranes have been investigated, exhibiting promising results. Fig. 7 shows a multi-stage membrane system that recovers CO 2 from a shifted syngas stream proposed by Kaldis et al. 114 In this process, the clean syngas stream resulting from the coal gasifier and gas cleanup units is first shifted in a series of WGS units, resulting in a gaseous mixture consisting mainly of H 2,CO 2, CO, and N 2. The mixed gas is then introduced to a series of H 2 -selective membranes to recover a concentrated CO 2 stream on the retentate side. The permeate side, with concentrated Fig. 7 Multiple stage membrane system for CO 2 recovery. 114 hydrogen, is combusted in the gas turbine for electricity generation. The performances of both polymer and ceramic membranes are investigated using ASPEN Plus Ò simulations. The results indicated that the CO 2 emission can be reduced by over 50% using the multi-stage membrane system but with 17 28% parasitic energy consumptions. 114 More advanced membrane systems integrate the function of both WGS and CO 2 separation using either H 2 -orco 2 -selective membranes. Such configurations are shown in Figs. 8a and b. 63,92, Fig. 8 (a) Schematic of H 2 -selective membrane enhanced IGCC process. 118 (b) Schematic of CO 2 -selective membrane enhanced IGCC process Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

10 Fig. 8a illustrates a specific configuration when a H 2 -selective membrane is used. 63,92,115, In such a configuration, a conventional gasifier and a gas clean up system is used to produce clean syngas. The clean syngas is then sent to the membrane WGS reactor. The membrane WGS reactor has two compartments, i.e. reaction side and product side. The two compartments are segregated by a semi-permeable membrane that is selective to hydrogen. In the reaction side, the CO in the syngas is converted to H 2 and CO 2 via WGS reaction. The H 2 produced in the reaction side is continuously permeated through the membrane to the product side. As a result, a high purity H 2 product can be obtained without engaging traditional separation techniques. Such hydrogen can either be used as a product or combusted with air for power generation. In addition, due to the removal of the hydrogen product, the WGS reaction, which is limited by thermodynamic equilibrium, can be enhanced. The tail gas from the reaction side, with a high CO 2 concentration mixed with residual CO and H 2, is combusted in a combined cycle system with O 2 to generate electricity. The resulting CO 2 is then sequestered. The underlying principle for the membrane-based system shown in Fig. 8b 116,118 is similar to that of the system shown in Fig. 8a. The only difference lies in the type of membrane used for separating the shifted syngas. In this configuration, a CO 2 - selective membrane is used to divide the reaction side and the product side in the membrane reactor. As a result, the CO 2 rather than the H 2 will be transferred from the reaction side to the product side. The simultaneous removal of CO 2, which is another product of the WGS reaction, can also enhance the reaction. The CO 2 stream in the product side, swept by steam, can be directly sequestered while the H 2 -rich stream in the reaction side can either be purified to obtain a hydrogen product or combusted with air for power generation. Extensive studies have been performed to analyze the performance of gasification processes integrated with membrane systems. Chiesa et al. (2007) 119 indicated that although a significant energy penalty has to be paid for CO 2 capture, a Pd-based membrane system such as that shown in Fig. 8a is thermodynamically advantageous when compared to commercial WGS CO 2 capture systems. A process analysis carried out by Amelio et al. (2007) 115 indicated that if integrated with an IGCC system using a GE gasifier, an energy penalty around 17.5% (46.0% before capture to 39.3% HHV after capture) will incur when a Pd-based H 2 -selective membrane system is used to capture 90% of the CO 2. Grainger et al. (2008) 116 studied the performance of a CO 2 -selective polyvinylamine membrane in an IGCC system identical to the Puertollano plant. The results revealed a 22.9% energy penalty for 85% CO 2 capture. Carbo et al. 118 compared the performance of a H 2 -selective membrane system to that of a CO 2 -selective membrane in an IGCC process with an entrained flow, oxygen blown gasifier. The results indicated that the energy penalty is merely 11.2% when a H 2 -selective membrane is used for 100% CO 2 capture. In contrast, a 19.4% energy penalty will incur when a CO 2 - selective membrane is used for 90% CO 2 capture. The selectivity of both membranes was assumed to be infinity in this study. A more advanced approach integrates a H 2 -selective membrane into the gasifier for H 2 generation (Fig. 9). 121 In this case, a membrane is installed in the coal gasifier to separate out the hydrogen generated. The rest of the syngas is combusted with oxygen for power generation. Such a process, although potentially more efficient, requires a membrane that tolerates ultrahigh temperatures and various contaminants. The development of such high performance membranes may not be feasible in the near future. To generalize, although the membrane systems can not eliminate the energy penalty for CO 2 capture in gasification plants, they have the potential to reduce such a penalty when compared to the traditional approach. The parasitic energy consumed for CO 2 capture using a membrane-based system lies in the need for gas compression, and in some cases, the generation of extra oxygen to combust the CO 2 rich tail gas and the need for extra steam as sweep gas. It is also worth noting that from the economic standpoint, the membrane-wgs reactor can replace both the shift unit and CO 2 separation unit. Therefore, notable cost reduction can be realized provided that a membrane with good reliability and durability can be mass-produced at a reasonable cost. 4.2 Chemical looping based gasification systems As discussed in Section 4.1, membrane-based systems intensify the syngas conversion scheme by integrating the CO shift and Fig. 9 Integrated membrane separation with gasifier. 121 This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

11 the CO 2 removal step. Due to the limited tolerance of membranes towards pollutants such as sulfur and halogen compounds, the raw syngas from the gasifier needs to be extensively cleaned before entering the membrane system. Chemical looping based systems have the potential to simplify the syngas cleaning procedures. Moreover, the pressure drop due to the membrane separation can be reduced in chemical looping systems. The chemical looping strategy that generates the end products with the aid of chemical intermediates through a series of reaction schemes was proposed many years ago. One example is the steam-iron process used for commercial hydrogen production from coal derived producer gas in the early 20 th century. 122,123 Another example is the CO 2 generation, reported a half-century ago, for the beverage industry using the chemical looping process with the oxides of copper or iron as the looping particles. 124,125 Although the adoption of the chemical looping strategy in the early years was mainly prompted by the lack of effective chemical conversion/separation techniques in the product generation, modern applications of chemical looping processes are prompted by the need for developing an optimized reaction scheme that minimizes the exergy loss involved in the chemical/energy conversion system Also driven by the envisaged CO 2 emission control, the recent development in chemical looping systems have focused on the efficient conversion of gaseous carbonaceous fuels such as natural gas and coal derived syngas, 53, and solid fuels such as petroleum coke and coal 132,133 while separating CO 2 readily through the looping reaction scheme. In this section, chemical looping systems using coal derived syngas will be discussed. Looping systems that directly convert coal will be presented in Section 4.3. In this section, two types of chemical looping based approaches that enhance the performance of the coal gasification processes are given. Type A chemical looping such as the Syngas Chemical Looping Combustion (Syngas CLC) processes and the Syngas Chemical Looping (SCL) process use oxygen carrier particles, typically metal oxides, to convert coal derived syngas, whereas Type B chemical looping such as the Calcium Looping Process (CLP) and the Thermal Swing Sorption Enhanced Reaction (TSSER) process utilize solid CO 2 sorbents to enhance the syngas conversions Type A chemical looping. Based on the type of the end product, the Type A chemical looping processes can be divided into two sub-categories, i.e., chemical looping combustion 85, where the chemical intermediate is first reduced and then combusted with air to generate heat, and chemical looping gasification 131, where fuel gas such as hydrogen is produced. Syngas chemical looping combustion. Fig. 10 shows a typical chemical looping combustion process using coal derived syngas as feedstock. As can be seen, coal is first gasified into raw syngas. A set of gas cleanup units is then used to remove the contaminants to a level below the tolerance limit of the oxygen carrier particle used in the process. The cleaned syngas then reacts with the oxygen carrier particles in the first reactor which is noted as the reducer or the fuel reactor. The main reactions in this reactor are: MeO + H 2 / Me + H 2 O (3) MeO + CO / Me + CO 2 (4) As can be seen from reaction 3 and 4, the syngas is oxidized to CO 2 and steam by the metal oxide particles before exiting the reducer. A concentrated CO 2 stream can then be readily obtained by condensing out the steam in the reducer. The CO 2 stream can be further pressurized and transported for sequestration. Meanwhile, the reduced metal oxide particles will be introduced to the second reactor, i.e. the combustor or the air reactor, to react with air: Me + 1/2O 2 (Air) / MeO (5) The oxidization reaction in the combustor is highly exothermic. As a result, a high temperature, high pressure, oxygen depleted exhaust gas stream is generated from the combustor. Such an exhaust gas stream is used to drive a combined cycle system for electricity generation. Meanwhile, Fig. 10 Schematic flow diagram of syngas chemical looping combustion processes. 258 Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

12 the particles, fully regenerated by air, are recycled to the reducer for another redox (reduction oxidation) cycle. In the CLC process, the coal derived syngas is combusted with air indirectly through the looping particles, i.e., metal oxide. Hence, the fuel combustion products, i.e.,co 2 and steam are not diluted by nitrogen in the air, and the CO 2 separation from nitrogen is, therefore, avoided. Moreover, the syngas cleanup steps can potentially be simplified since the metal oxide particles can be more robust towards contaminants when compared to membranes. 85 As a result, the acceptable level of the contamination in the syngas for chemical looping processes can be higher than the membrane based systems. An additional advantage for the looping system is that the difference between the pressure of the concentrated CO 2 exhaust and that of the syngas feedstock is merely the pressure drop of the reducer, which can be significantly lower than the pressure drop in the solvent-based and membrane-based CO 2 separation system. The focal areas of the research and development activities on the CLC processes are on the oxygen carrier particle design and synthesis, looping reactor design and operation, and looping process analysis and demonstration. Various types of oxygen carrier particles, including the oxides of Ni, Fe, Mn, Cu, and Co, have been investigated for syngas chemical looping combustion. 129, Most of the studies focus on developing particles that maintain good reactivity for multiple redox (reduction oxidation) cycles. Other factors being considered include particle strength improvements and carbon deposition reduction. In order to obtain particles with the desirable properties, ceramic materials are often used to support the oxygen carrier. These supporting materials include alumina, MgAl 2 O 4, yttria-stabilized zirconia (YSZ), TiO 2, bentonite, and barium hexaaluminate (BHA). Metal oxide particles that can sustain multiple redox cycles in atmospheric reactor systems have been successfully synthesized. Important areas that need to be further explored include the pollutant tolerance of the particles and particle reactivity under elevated pressures. For instance, experiments in a high pressure TGA indicated that an increase in total pressure may have negative effects on the reduction rates of Cu, Ni, and Fe based oxygen carriers. 143 This finding, however, was inconsistent with that obtained by Siriwardane et al. (2007) using NiO supported on bentonite. 141 Jin and Ishida (2004) studied the pressure effect on the reactivity of NiO supported on MgAl 2 O 4 under MPa (1 9 atm) using a fixed bed reactor. 129 They found that an increased carbon deposition under elevated pressures, which was consistent with that predicted from thermodynamic principles. 85 An increased oxidation reaction rate was also observed under higher pressure by Jin and Ishida (2004); 129 however, the pressure effect on the reduction reaction rate was not reported. The syngas CLC process was tested in a 300 W th (watts thermal) circulating fluidized bed chemical looping combustor at Chalmers University in Sweden Different types of oxygen carrier particles including NiO supported on MgAl 2 O 4, 144 Fe 2 O 3 supported on Al 2 O 3, 147 and Mn 3 O 4 supported on Mg stabilized 148,149 ZrO 2 have been used, yielding 99% or higher syngas conversions. Other CLC testing facilities include the 10 kw th circulating fluidized bed unit at Chalmers University, 130 the 50 kw th circulating fluidized bed unit at Korea Institute of Energy Research (KIER), 150 and the 120 kw th circulating fluidized bed unit at Vienna University of Technology. 151 The published experimental results obtained from these testing facilities focus on the conversion of methane. Both thermodynamic and ASPENÒ plus simulations have been performed for the chemical looping combustion systems with syngas as feedstock. The exergy analysis conducted by Anheden and Syedberg (1998) indicated that when a CLC system with a Fe 2 O 3 -based oxygen carrier particle is used to a retrofit IGCC plant, a 7.8% increase in exergetic efficiency compared to a base case can be realized (from to 48.72%). 126 In their study, however, the energy for CO 2 compression was not considered. The ASPENÒ simulation conducted by Xiang et al. (2008) indicated that the gasification CLC system has the potential to achieve 43.2% (LHV) efficiency for electricity generation with 99% CO 2 captured. 134 The performance of the syngas chemical looping combustion processes is dependent on two closely related factors, i.e. the oxygen carrier particle performance and the reactor design. Many research efforts on the CLC system have focused on the development of reactive and recyclable particles, given that fluidized bed reactors are to be used as the looping reactors. In fact, various factors need to be considered in selecting a particle, i.e., particle oxygen carrying capacity, reactivity, recyclability, cost, physical strength, oxygen carrying capacity, contaminant tolerance, melting points, and environmental effects. On the looping reactor, the use of fluidized bed reactor is evidenced by extensive on-going studies of high density circulating fluidized bed systems in which the riser serves as the combustor and the downer in bubbling or turbulent mode of operation serves as the reducer in chemical looping combustion applications. 44,144,149,152 It should be noted, however, that reactor design can have a significant effect on particle conversion, and hence the process efficiency. Table 5 illustrates the effect of the flow pattern, i.e., fluidized bed or countercurrent moving bed in the fuel reactor on the solid particle conversion when a Fe based oxygen carrier particle is used. The results given in the table are based on the thermodynamic analysis and the assumptions presented in the table. It is seen that the theoretical solid conversion in the moving bed is nearly five times higher than that in the fluidized bed, resulting in significantly reduced solid circulation rate for the Table 5 Reactor type Reducer performances using different reactor designs Countercurrent moving bed Oxygen carrier Fe 2 O 3 Fe 2 O 3 Maximum metal oxide conversion b (%) Effective oxygen carrying capacity c (wt %) CO + H 2 concentration in gas exhaust (%) Fluidized bed/cstr a a To account for back mixing in the fluidized bed reducer, the fluidized bed reactor is considered as CSTR. b Maximum metal oxide reduction at 850 C when more than 99.9% syngas (CO : H 2 ¼ 2 : 1) is converted. Results were obtained based on thermodynamic analysis. 153c Effective oxygen carrying capacity ¼ Maximum oxygen carrying capacity Metal oxide loading Maximum theoretical metal oxide conversion (metal oxide loading is 70% in this case). This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,

13 Downloaded on 06 October 2012 Fig. 11 moving bed design and hence minimized reactor volume. Thus, for a successful CLC system operation, flow pattern consideration for the reactor is deemed important. Syngas chemical looping gasification. Compared to the CLC processes, the Syngas Chemical Looping (SCL) process has the flexibility to co-produce hydrogen and electricity. 131, Fig. 11 shows a simplified block diagram of the SCL process developed at the Ohio State University. The SCL process can convert syngas with moderate levels of HCl, NH 3, sulfur, and mercury; therefore, existing hot gas cleanup units (HGCU) will be adequate for raw syngas cleaning. The raw syngas exiting the HGCU will be introduced to the reducer, which is a moving bed of specially tailored iron oxide composite particles operated under a pressure similar to that of the syngas. In this reactor, the syngas is completely converted into carbon dioxide and water while the iron oxide composite particles are reduced to a mixture of Fe and FeO under C: Fe 2 O 3 +CO/ 2FeO + CO 2 (6) FeO + CO / Fe + CO 2 (7) Fe 2 O 3 +H 2 / 2FeO + H 2 O (8) FeO + H 2 / Fe +H 2 O (9) Similar to the CLC processes, an exhaust stream with concentrated CO 2 can be obtained from the reducer. The contaminants in the syngas will also exit the reducer with the CO 2 stream without attaching to the particle. These contaminants can be compressed and sequestered along with CO 2 if allowed by regulation. As a result, the gas cleaning procedures are greatly simplified. The Fe/FeO particles leaving the reducer are then introduced into the oxidizer which is operated at C at a pressure similar to that of the reducer. In the oxidizer, the reduced Simplified schematic of the Syngas Chemical Looping process. particles react with steam to produce a gas stream that contains solely H 2 and unconverted steam. The steam can be easily condensed out to obtain a high purity H 2 stream. The reactions involved in the oxidizer include: Fe + H 2 O (g) / FeO + H 2 (10) 3FeO + H 2 O (g) / Fe 3 O 4 +H 2 (11) The steam used in the oxidizer is produced from the heat released from syngas cooling and reducer/oxidizer exhaust gas cooling. In the SCL process, the oxidizer is slightly exothermic while the reducer can either be slightly exothermic or slightly endothermic depending on the syngas composition. Therefore, both reducer and oxidizer are operated under the adiabatic conditions. Heat is provided to or removed from the reactors by the oxygen carrier particles and the exhaust gas. The Fe 3 O 4 formed in the reducer reactor is regenerated to Fe 2 O 3 in an entrained flow combustor which also transports solid particles discharged from the oxidizer to the reducer. A portion of the heat produced from the oxidation of Fe 3 O 4 to Fe 2 O 3 can be transferred to the reducer through the particles: 4Fe 3 O 4 +O 2 / 6Fe 2 O 3 (12) The high pressure (>2.5 MPa, depending on the gasifier type), high temperature (>1000 C), spent air produced from the combustor can be used to drive a gas turbine steam turbine combined cycle system to generate electricity for parasitic energy consumptions. In yet another configuration, a fraction or all of the reduced particles from the reducer can bypass the oxidizer and be introduced directly to the combustor if more heat or electricity is desired. Hence, both chemical-looping reforming and chemical-looping combustion concepts are applied in the SCL system, rendering it a versatile technology for H 2 and electricity co-production. The SCL process has been tested at Ohio State University (OSU) in a 2.5 kw th bench scale moving bed unit for a combined 260 Energy Environ. Sci., 2008, 1, This journal is ª The Royal Society of Chemistry 2008

14 operating time of >100 h. 154 Current testing results indicate) >99.9% syngas conversion in the reducer and >99.95% purity hydrogen stream from the oxidizer. Nearly full conversion of gaseous hydrocarbons such as CH 4 was also obtained. A 25 kw th SCL demonstration unit is being constructed at OSU. The process analysis based on the bench scale testing results indicated that the overall efficiency for the SCL process can exceed 64% (HHV) with 100% CO 2 capture. For comparison, the efficiency of a traditional coal-to-hydrogen process with 90% CO 2 capture is estimated to be 57% (HHV). 155 Besides serving as a stand alone hydrogen/electricity producer, the SCL process can be integrated into other processes to improve the overall energy conversion scheme. Fig. 12 exemplifies the integration of the SCL process to the state-of-the-art Coal-to-Liquids (CTL) process. 156 In this configuration, the SCL system converts the C 1 C 4 products from the Fischer Tropsch (FT) reactor into H 2 and recycles it to the F T reactor as feedstock, resulting in a 10% increase in the liquid fuel yield and a 19% reduction in CO 2 emissions. 157 Oxygen carriers other than iron oxide such as NiO were also explored for hydrogen generation from syngas. The experiments carried out in a 20 mm I.D. fixed bed reactor, however, indicated that Fe is a more favorable choice than Ni. 158,159 Svodoba et al. (2007,2008) 160,161 also examined, using thermodynamic principles, the feasibility of using Fe, Mn, Ni, Cr, and Co based particles for hydrogen production. They concluded that Fe Fe 3 O 4 is more suitable for chemical looping gasification compared to other particles; however, they further stated that Fe 3 O 4 is more difficult to reduce based on a fluidized bed design. Xiang et al. (2007) performed ASPEN Plus Ò simulation on an iron-based looping system for hydrogen generation. 162 In their system, reduced iron oxide is only regenerated to Fe 3 O 4 rather than Fe 2 O 3. As a result, a significant amount of syngas will leave the reducer unconverted. Based on the simulation results, the system has an energy conversion efficiency as high as 58.33% (LHV) Type B chemical looping systems. The Type B chemical looping system uses a CO 2 sorbent to enhance the WGS reaction of syngas by simultaneous removal of the CO 2 generated during the shift reaction. The sorbents include CaO, which is used in the Calcium Looping Process (CLP), and K 2 CO 3 promoted hydrotalcite and Na 2 O promoted alumina, both used in the thermal swing sorption enhanced reaction (TSSER) process. Calcium looping process (CLP). Fig. 13 shows the schematic integration of the calcium looping process in a typical coal gasification system for the production of hydrogen. 52,156,163,164 As shown in Fig. 13, the calcium looping process comprises two reactors: the carbonation reactor (carbonator), which produces high purity hydrogen while removing contaminants, and the calciner, where the calcium sorbent is regenerated and a concentrated CO 2 stream is produced. The carbonator is operated at C and 2 3 MPa (20 30 atm). In the carbonator, the CO 2 generated by the WGS reaction is simultaneously removed by a CaO sorbent. The mesoporous, precipitated calcium carbonate (PCC CaO) sorbent has much higher reactivity and CO 2 capture capacity (40 36 wt % for 50 th 100 th cycles) when compared to most of the high temperature Fig. 13 Schematic flow diagram of the calcium looping process. Fig. 12 Syngas Chemical Looping enhanced Coal-to-Liquids (SCL CTL) process. This journal is ª The Royal Society of Chemistry 2008 Energy Environ. Sci., 2008, 1,