ABSTRACT
Seven different types of gasification-based coal conversion processes for producing mainly electricity and in some cases hydrogen (H2), with and without carbon dioxide (CO2) capture, were compared on a consistent basis through simulation studies. The flowsheet for each process was developed in a chemical process simulation tool “Aspen Plus”. The pressure swing adsorption (PSA), physical absorption (Selexol), and chemical looping combustion (CLC) technologies were separately analyzed for processes with CO2 capture. The performances of the above three capture technologies were compared with respect to energetic and exergetic efficiencies, and the level of CO2 emission. The effect of air separation unit (ASU) and gas turbine (GT) integration on the power output of all the CO2 capture cases is assessed. Sensitivity analysis was carried out for the CLC process (electricity-only case) to examine the effect of temperature and water- cooling of the air reactor on the overall efficiency of the process. The results show that, when only electricity production in considered, the case using CLC technology has an electrical efficiency 1.3% and 2.3% higher than the PSA and Selexol based cases, respectively. The CLC based process achieves an overall CO2 capture efficiency of 99.9% in contrast to 89.9% for PSA and 93.5% for Selexol based processes. The overall efficiency of the CLC case for combined electricity and H2 production is marginally higher (by 0.3%) than Selexol and lower (by 0.6%) than PSA cases. The integration between the ASU and GT units benefits all three technologies in terms of electrical efficiency. Furthermore, our results suggest that it is favorable to operate the air reactor of the CLC process at higher temperatures with excess air supply in order to achieve higher power efficiency.
1. INTRODUCTION
Energy is the backbone of every modern society. On the other hand, its production is one of the key contributors toward the global climate change. In particular, power plants produce both electricity and CO2 by combusting fossil fuels, which is one of the major sources of total man made CO2 emissions worldwide.1,2 Future forecasts for the economic growth in Asia Pacific and industrial development in Africa indicate that the total world energy demand will increase from 462 quadrillion British Thermal Units (BTU) in 2005 to over 695 quadrillion BTU by 2030.3 The exponential rise in emissions of CO2 from fossil fuel utilization to around 30 Gt per year will lead to significant climate change unless the emissions are captured and stored.4
Developing clean and affordable energy with abundant supply is an issue of international concern. Until recently, the prime focus of the research on power generation was on improving energy efficiency and switching from fossil fuels toward less carbon intensive (renewable) energy sources. The renewable energy technologies can reduce CO2 emissions but are still costly. Even if they are made cost-competitive in the next few years, they will still need time to penetrate the market. Some researchers consider coal as the primary source of energy at least for the next 5−6 decades since its supply will last over 150 years compared with 50−60 years for oil and natural gas.5 Thus, there is a large international research effort toward developing technologies to use coal in an environmentally sustainable manner.6
Developing clean and affordable energy with abundant supply is an issue of international concern. Until recently, the prime focus of the research on power generation was on improving energy efficiency and switching from fossil fuels toward less carbon intensive (renewable) energy sources. The renewable energy technologies can reduce CO2 emissions but are still costly. Even if they are made cost-competitive in the next few years, they will still need time to penetrate the market. Some researchers consider coal as the primary source of energy at least for the next 5−6 decades since its supply will last over 150 years compared with 50−60 years for oil and natural gas.5 Thus, there is a large international research effort toward developing technologies to use coal in an environmentally sustainable manner.6
Table 1. Summary of Literature Review on the Comparison of Different Coal to Electricity and H2 Conversion Technologies with and without CCS
In the recent years, carbon capture and storage (CCS) has been considered to offer “end-of-pipe” technologies that can allow continuous use of fossil fuels with low or almost negligible emissions. A review by Boot-Handford et al.7 has comprehensively discussed the recent developments, challenges, and potential future improvements in different types of CCS technologies. Table 1 shows a summary of a number of studies on selection of a promising CCS technology that can produce electricity and, in some cases, H2 from fossil fuels. For instance, Chiesa et al.8 compared different scenarios consider- ing CO2 venting and CO2 capture using integrated gasification combined cycle (IGCC) technology for the production of H2 and electricity from coal. Physical absorption and adsorption processes were assumed for CO2 and H2 separation, respectively. They8 concluded that, with an emissions constraint, there are very small thermodynamic benefits of coproduction relative to stand-alone electricity and H2 production. Damen et al.9 reviewed various concepts including oxyfuel combustion, membrane separation, physical absorption, and chemical absorption processes for electricity and H2 production from coal and natural gas with CCS. A number of critical factors were identified and compared, including efficiency, cost of energy (COE), cost of H2 (COH), and CO2 avoidance costs. Also assessed were the impact of fuel prices on electricity and H2 production costs for pulverized coal (PC), natural gas combined combustion (NGCC), and IGCC plants. The analysis showed that with CO2 capture, the net electrical efficiencies are 30−35% for PC, 32−40% for IGCC, and 43−50% for NGCC power plants. Also, both the chemical and physical absorption processes can achieve 85−90% CO2 capture efficiency with the precapture technologies being more suitable for IGCC plants. Cormos10 describes the methodology to evaluate the performance of a coproduction (electricity and H2) IGCC power plant with physical absorption (Selexol)- based CO2 capture technology. The study examined the effect of using different feed stocks such as coal, sawdust, municipal solid waste, and food waste (meat and bone) on the power output. Later, Cormos11 compared different types of gasifiers using only coal as fuel and investigated the energy integration aspects in detail to optimize the overall plant efficiency of a coproduction IGCC plant with CCS. The study concludes that an entrained flow gasifier with dry feed and syngas heat recovery is a more promising concept than slurry feed and water quench design. Further work by Cormos12 presented a detailed methodology to assess the performance of an iron- based CLC system using critical design factors such as gasifier selection, gasifier feeding system, and overall energy efficiency. This work suggested that a CLC-based system has a low energy penalty compared to liquid absorption process for CO2 capture. Li and Fan13 addressed the energy conversion efficiencies for the chemical looping based coal conversion process. Their study shows that efficiencies of syngas chemical looping process is comparable with the current coal conversion processes for electricity and H2 generation and could be considered as a retrofit technology in the downstream of the present gasification processes. On the other hand, they found that coal direct chemical looping combustion (CDCLC) process is more energy efficient than coal gasification based CLC process.
In addition to the investigations on energy efficiency, there are a few studies on the exergetic efficiency of various CO2 capture technologies with combined electricity and H2 production. Exergy analysis combines the first and second laws of thermodynamics to identify the irreversibility and losses related to each unit or process of a system. For instance, Kunze, et al.14 presented the exergy analysis of an IGCC process by dividing the plant into three sections, the gasifier, gas treatment, and combined cycle. The analysis shows that 60% of the exergy is lost in the overall process; out of which, 31.1% is lost only in the combined cycle section, making it the most inefficient part of the process, followed by 17.1% in gas treating and 11.3% in the gasifier. Wang et al.15 computed the exergy penalty for CO2 capture in an IGCC process. Further, Anheden and Svedberg16 showed the exergy analysis of CLC system with different fuels and oxygen carriers (OCs). Their results indicate that efficiency of a CLC system is similar or higher than that of a conventional combustion process.
While the existing studies have provided useful evaluation of a range of power (and in some cases H2) generation schemes with or without CCS, their assumptions and considerations vary with respect to factors such as feedstock, power generation technology, CCS technology, production scale, and modeling approaches adopted, making it difficult to compare their results. To address this deficiency, our work uses a single basis of analysis in terms of the feedstock type, production scale, and modeling assumptions. This makes it easier and more straightforward to compare various gasification-coupled coal power plants with and without the CCS producing electricity and possibly H2. This work provides a methodology to assess different CO2 capture technologies based on mainly energy, exergy, and CO2 capture efficiencies. The processes evaluated here include (i) IGCC for power generation without CCS, (ii) IGCC for power (and H2) generation with two different precombustion CCS options based on physical absorption and adsorption, and (iii) power (and H2) generation with CLC. Comparison is also made on the basis of the effect of ASU and GT unit integration for each of the three capture technologies. The effect of different operating conditions such as air reactor temperature and water cooling of the air reactor in the CLC process on the net electrical efficiency is another distinct feature of the present work. The findings of this work evaluate the suitability of physical absorption, physical adsorption, and CLC based CO2 capture technologies for coal power plants by indicating the differences in overall plant performance with each type of capture technology. This article also predicts the behavior of the CLC process at different operating conditions (as stated above), which can be useful in pilot scale experimental studies.
A literature review of advanced CCS technologies has been first carried out to gather information on technical inputs and parameters such as the component flow rates, temperature, pressure, and efficiencies for various units, required for process modeling. The chemical process simulation tool Aspen Plus, was used to develop the flowsheet models for seven different coal gasification based power plant configurations at a nominal power output of up to 467 MW. The electricity generation, H2 production, CO2 emission and other performance indicators such as energy and exergy efficiencies are subsequently analyzed.
2. METHODOLOGY
2.1.Process Description. Seven different types of coal gasification based power plant configurations, with and without CO2 capture, at a power output between 141 and 467 MW have been considered. A brief description of each process is given in Table 2.
Table 2. Description of Different Cases Used in the Study
The chemical process simulation tool Aspen Plus was used to develop and simulate a process flowsheet for each case. The base case (case 0) considered in this work is an IGCC plant producing only electricity without any CO2 capture. The flowsheets for cases 1−4 are conventional IGCC process with precombustion based CO2 capture and cases 5−6 are gasification-coupled CLC process for CO2 capture. Cases 1, 2, and 5 generate electricity only while the cases 3, 4, and 6 produce both electricity and H2. A stand-alone ASU generating 95% pure O2 has been used in all seven cases, followed by an O2-blown entrained flow shell gasifier operating at 30 atm, and fuel conversion ratio of 99.9%.11 The power consumption by the ASU is assumed to be 225 kWh/tonne of O2 produced.11 The dry pulverized coal (100 μm in size) is pressurized in a lock hopper and fed to the gasifier vessel along with O2 from the top. The coal is partially oxidized by O2 in the gasifier to produce syngas, which mainly consists of CO and H2. The exothermic nature of the partial oxidation reaction of coal inside the gasifier provides the heat to achieve and maintain the desired temperature of 1300 °C which is above the melting point of ash.8 The excess heat generated in the gasifier is removed by the generation of high pressure (HP) steam. The slag in liquid form flows down the walls and comes out at the bottom with syngas. The syngas can be either quenched with water or cooled in radiative and convective heat exchanger.8 Water quenching degrades the thermal energy of the hot syngas stream. Therefore, in our study, the syngas from the gasifier is cooled in a heat exchanger, which allows production of HP steam.
2.1.1. IGCC with Precombustion Based CO2 Capture. This section describes the configuration of cases 1 to 4, which use PSA and Selexol technologies for CO2 capture. First, an IGCC process producing only electricity with PSA technology for CO2 capture (case 1), shown in Figure 1a, was developed. The detailed process flow diagram of case 1 can be seen in Supporting Information (SI) Figure S.1. In this process, the hot syngas stream at 1300 °C from the gasifier is cooled to 350 °C in a convective heat exchanger in the heat recovery steam generation (HRSG) unit where HP water used for cooling is converted into a HP steam. The cooled syngas at 350 °C is sent to two water−gas shift reactors (WGS-1 and WGS-2) aligned in series operating at temperatures 350 and 178 °C, respectively.17,18 The WGS-1 reactor is supplied with steam at 30 atm and 350 °C generated in the HRSG. The CO in the syngas stream is partially converted to CO2 by the steam in WGS-1 reactor generating more H2 in the syngas. The syngas and steam exiting the WGS-1 reactor at 350 °C are cooled to 178 °C before both are fed to the WGS-2 reactor where up to 98% of the remaining CO is converted to CO2.19 The heat released by the cooling of syngas from 350 to 178 °C is used for preheating the boiler feedwater in the HRSG. The conversion of CO into CO2 in the WGS reactors is an exothermic process which needs continuous removal of the excess heat to maintain the required reaction temperatures. Pressurised boiler feedwater is used as the coolant in the two WGS reactors. The syngas exiting the WGS-2 reactor at 178 °C is further cooled to 35 °C in the HRSG which condenses the steam and removes it before the syngas is sent to an acid gas removal (AGR) unit or a Selexol unit to remove sulfur; here nearly 99.9% of the hydrogen sulphide (H2S) is stripped from the syngas using Selexol (dimethyl ether of polyethylene glycol).12 The sulfur removed from the syngas in the form of H2S could be converted into elementary sulfur in a Claus plant.20 The Selexol in the sulfur removal unit is regenerated by heating which removes the dissolved sulfur and CO2. After removing sulfur, the syngas stream is passed through the PSA-CO2 unit where CO2 is adsorbed by the adsorbent material (activated carbon) and the remaining gases (Tail gas−1; see Figure 1a) exits with a pressure drop of 0.49 atm.21,22 The CO2 separation efficiency of the PSA unit is assumed to be between 90% and 95%.21 The adsorbent material in the PSA-CO2 chamber is regenerated by lowering the pressure to nearly atmospheric pressure level to release CO2.21,22 The released CO2 is then compressed to 150 atm for transportation and storage.23 Case 1 does not produce any H2, and therefore H2-rich Tail gas-1 follows route II (as seen in Figure 1a), which is then supplied to the combustor of the GT unit after reheated to 350 °C. The high temperature exhaust gases from the GT are cooled in the HRSG unit before it is finally released to the atmosphere. The syngas and flue gas stream temperatures for case 1 are noted in SI Table S.1. The HP steam generated at 600 °C in the overall process (gasifier, heat exchangers, HRSG) is expanded through the HP, intermediate pressure (IP) and low pressure (LP) steam turbines. The exhaust steam from the HP and IP steam turbines are reheated to 600 °C before further expansion through the IP and LP turbines. The details of water and steam cycle as well as the temperature and mass flow rate of steam and water for case 1 are provided in the SI Section S.1 and Table S.2, respectively.
Case 2, which uses a Selexol-based physical absorption CO2 capture unit (also known as acid gas removal or AGR unit) instead of a PSA- CO2 unit after sulfur removal, is shown in Figure 1b. In this process, the outgoing gas stream from the sulfur removal unit, containing mainly CO2 and H2, is passed through the AGR-CO2 unit which separates CO2 from rest of the gases. The Selexol is regenerated by reducing the pressure to atmospheric level which releases the absorbed CO2.8 The CO2 is then compressed to up to 150 atm after condensing any vapor present in the stream. After CO2 removal, the remaining gases (Tail gas-1) are used in the GT unit as in case 1, following route II.
Case 2, which uses a Selexol-based physical absorption CO2 capture unit (also known as acid gas removal or AGR unit) instead of a PSA- CO2 unit after sulfur removal, is shown in Figure 1b. In this process, the outgoing gas stream from the sulfur removal unit, containing mainly CO2 and H2, is passed through the AGR-CO2 unit which separates CO2 from rest of the gases. The Selexol is regenerated by reducing the pressure to atmospheric level which releases the absorbed CO2.8 The CO2 is then compressed to up to 150 atm after condensing any vapor present in the stream. After CO2 removal, the remaining gases (Tail gas-1) are used in the GT unit as in case 1, following route II.
Case 3, which is shown in Figure 1a, is a variant of case 1, with combined electricity and H2 production. The stream from PSA-CO2 enters PSA-H2 installed for H2 separation, following route I instead of route II. A 99.99% pure stream of H2 exits the PSA-H2 unit after 0.49 atm of pressure drop.8 The separation efficiency for H2 in the PSA-H2 unit is assumed to be 85%.8,10 The output H2 stream is compressed to 60 atm for transportation and storage.8 The leftover gas (Tail gas-2) after H2 separation leaves PSA-H2 at nearly atmospheric pressure; hence, it needs to be compressed to the GT combustor pressure (21 atm). If more electrical energy is required, some amount of separated pure H2 can be purged to the GT combustor according to the requirement. The remaining pure H2 stream is compressed to 60 atm for storage. The high temperature GT exhaust is passed through the HRSG to produce HP steam and for steam reheating. Case 4, shown in Figure 1b, has an AGR-CO2 unit for CO2 removal instead of a PSA- CO2 unit used in case 3. Apart from this difference, the rest of the downstream path after CO2 removal is same as described above for case 3, which is following route I instead of route II.
2.1.2. CLC-Based Processes. A CLC process is based on transferring oxygen to the fuel from air or steam by means of a OC. An OC could be made of metal or synthetic material that is capable of carrying oxygen and has excellent mechanical properties to withstand attrition, agglomeration and physical stress of recycling at high temperatures.
Figure 1. Simplified block flow diagrams of coal gasification-based power plant: (a) IGCC with PSA based CO2 capture technology (cases 1 and 3); (b) IGCC with selexol based CO2 capture (cases 2 and 4); (c) gasification-coupled CLC based CO2 capture producing electricity only (case 5); (d) gasification-coupled CLC based CO2 capture producing combined electricity and H2 (case 6).
This work assumes hematite (Fe2O3) as the OC, supported with 15% aluminum oxide (Al2O3) and 15% silicon carbide (SiC) to enhance its mechanical and physical properties.24 Parts c and d of Figure 1 show the block diagram of cases 5 and 6, respectively. In cases 5 and 6, the syngas from the coal gasifier is cooled to 35 °C in HRSG and supplied to a Selexol based sulfur removal unit. The syngas is then sent to a fluidized bed fuel reactor of the CLC process (after reheated to 350°C) represented by two fuel reactors, FR 1 and FR 2 (see Figure 1c,d).25 In the fuel reactors, H2 and CO are oxidized into H2O and CO2 after coming in contact with Fe2O3. The Fe2O3 is first partially reduced to magnetite (Fe3O4) in FR 1 and then completely reduced to wustite (Fe0.947O) in FR 2,12,25 as shown in Figure 1c and d. A cyclone separator removes the reduced OC particles from the hot gases coming out of the FR 2. These hot gases are cooled in a HRSG unit to condense the water vapor and produce a pure stream of CO2, which is compressed to 150 atm for storage. The sensible heat lost by the hot gases from the CLC fuel reactor is used to generate HP steam and for steam reheating. In case 5, the reduced OC particles (Fe0.947O) are fully regenerated to Fe2O3 in the air reactor where they are oxidized by pressurized air, which also helps in circulation of OC in the system. The oxidation of Fe0.947O by air is a highly exothermic process. The air reactor is maintained at 1300 °C by supplying excess air than usually required for OC regeneration.26 The hot pressurized air exiting the air reactor is separated from the OC particles in a cyclone separator and expanded in an air turbine. The regenerated OC particles are recycled back to the FR 1. The air turbine exhaust has a high temperature and, therefore, is sent to the HRSG unit for heat recovery before released to the atmosphere. The steam generated in the whole process (i.e., gasifier, CLC reactors, HRSG and other heat exchangers) is used to drive the HP, IP, and LP steam turbines. As in cases without CLC, the exhaust steam from the HP and IP steam turbines is reheated in the HRSG unit to 600 °C before expanding through IP and LP steam turbines.
In case 6, the reduced OC from the fuel reactors is partially oxidized to Fe3O4 in the steam reactor using steam at 30 atm and 350 °C generated in the HRSG unit. This oxidation reaction of the OC is an exothermic process that generates H2, which with some steam and OC particles comes out from the exhaust of the steam reactor maintained at 550 °C through HP water/steam cooling. The OC particles are separated from the steam and H2 in a cyclone separator and sent for complete oxidation to Fe2O3 by compressed air (which is again an exothermic reaction) in an air reactor (see Figure 1d). The hot mixture of H2 and steam after OC separation is cooled in HRSG unit that causes the steam to condense, generating a pure stream of pressurized H2 for further compression to 60 atm and storage. The hot pressurized air from the air reactor is expanded in an air turbine and then supplied to the HRSG unit before it is finally released to the atmosphere. Equations 1 to 7 represent the reactions taking place inside the reactors of a CLC process using an iron based OC.
Fuel Reactor.
2.2. Modeling Assumption and Simulation. The key modeling information and choices used in the simulations are shown in Tables 3 and 4. Table 3 shows the physical and chemical properties of Illinois #6 type coal used as fuel in all the cases. The stream class from Aspen Plus used in all cases is MIXCINC. The databanks selected for Aspen Plus simulations are COMBUST, INORGANIC, SOLIDS, and PURE22.24,27 The PR-BM property method is adopted for conven- tional components.24 Coal and ash used in the simulation models are considered as nonconventional components; therefore, information about their physical and chemical properties is needed. The property methods used for coal and ash are HCOALGEN and DCOALIGT, respectively.28 The OC and support materials are entered as solid in the component input data in Aspen Plus. The Barin equation is used to calculate the physical properties of the solid compounds.24 The model retrieves the CPSXP (a−h) coefficients from the INORGANIC databank of Aspen.24
Table 3. Physical and Chemical Properties of Illinois #6 Coal
Table 4. Design Assumptions Used for Developing the Process Flowsheets for CO2 Capture Cases
The key conditions and input parameters of each process unit such as gasifier, ASU, turbines, and reactors are presented in Table 4. In all the seven processes studied in this work, the raw syngas is produced in a conventional gasification process represented by a RYILED decomposer and a RGIBBS gasifier unit. A detailed description of reactor modeling is given in Section 2.3. Four-stage adiabatic compressors represented by the MCOMPR model in Aspen Plus, are used for gas compression. These compressors need the discharge pressure from the final stage and isentropic efficiency as the input to the Aspen Plus model. The Aspen Plus PUMP models with an isentropic efficiency of 90% have been used to simulate pressurization of the water needed for steam generation. For heat recovery steam generation (HRSG), MHeatX type counter current heat exchangers are used.
2.3.Reactor Modeling for the CLC Process. This section describes the reactor models used in the simulations. The built-in Aspen Plus reactor models RYIELD and RGIBBS are used to design different reactive processes including (i) gasification, (ii) WGS reaction, (iii) oxidation of fuel in fuel reactor, and (iv) OC regeneration in steam and air reactor.
2.3.1.Gasification. A dry feed type entrained flow shell gasifier is considered in this work due to its dominance in the commercial IGCC plant designs. An RYIELD reactor block is used to decompose the pulverized coal powder into its conventional constituent elements and also calculates the heat required for it. RYIELD reactors are used where inlets are unknown and the outlets known. The conventional elements provided after decomposition of coal are fed to the RGIBBS reactor block, which determines the possible products and their composition at equilibrium conditions. The RGIBBS reactor is an equilibrium based reactor, which restricts individual equations to equilibrium and does not take account of the reaction kinetics. This type of reactor considers all the components as possible products, which is useful when there are many reactions between several components and the reaction kinetics is unknown. The operating temperature, pressure and O2 to coal ratio are the key parameters required as input to the RGIBBS reactor.
2.3.2.WGS Reactor. A two stage WGS reaction has been considered in cases 1−4. These reactors are supplied with hot syngas and steam at 30 atm at 350 and 178 °C, respectively. A WGS reactor is modeled by using a REquil block, which is an equilibrium based reactor in Aspen Plus. This block is useful when there are few reactions and the reaction kinetics is unknown. It combines the chemical and phase equilibrium to generate the products of reaction. The temperature, pressure, and the chemical reaction equations are the key parameters required as input to a REquil reactor.
2.3.3. CLC Fuel Reactor. The reactants and products of the CLC fuel reactors are assumed to be well-mixed. Simple RGIBBS reactor blocks of Aspen Plus are used for the simulation of the CLC fuel oxidization process under equilibrium conditions. The operating temperature, pressure, and molar flow of OC particles and syngas are the key input parameters required for this model. The temperature and pressure are considered to remain constant. The reactions taking place inside the fuel reactors are endothermic and require heat, which is provided by high temperature OC particles (Fe2O3) supplied from the air reactor.
2.3.4. CLC Steam and Air Reactor. The steam reactor of a CLC system uses steam to partially oxidize the reduced OC particles to Fe3O4 while generating H2 as a product at thermodynamic equilibrium. The H2 yield of the steam reactor is directly proportional to the OC conversion. The steam reactor was modeled in Aspen Plus by using a single RGIBBS reactor block. The key operating parameters used for modeling the steam reactor are operating temperature, pressure and molar flow ratio between steam and OC. The air reactor effected complete oxidization of the reduced OC particles to Fe2O3 and was modeled as an entrained bed reactor with air and OC particles flowing cocurrently through the vessel. The combustor model, operating at a constant temperature and pressure, was used to predict the excess heat produced and the possible products. All of the combustion reactions are assumed to be fully completed in the combustor and this was sufficiently modeled using a RGIBBS model. The ratio between OC and air supplied and the operating temperature are the key variables for the air reactor model.
2.4. Plant Performance Indicators. All cases were evaluated from both the energy and exergy point of view. The assessment of the overall performance of all the processes was performed using streamflow data, for example, mass flow of the components, pressure, temperature, power, and energy output provided by the simulation of each process configuration. The terms discussed below are used as the key plant performance indicators.11,12
Gross electrical efficiency (ηgross) indicates the overall electricity produced by the steam and gas turbines used in the process. It does not consider the energy consumed by the auxiliary elements needed to run the plant and can be calculated using eq 8.
2.4.1. Exergy Analysis. Exergy is the maximum work that can be extracted from a system interacting with a reference environment, which is taken as 1 atm and 25 °C for this study.29 For a process stream, its exergy can be divided into two parts (physical and chemical).
Physical exergy (Exph) equals to the maximum reversible amount of work obtainable when a stream of substance is brought from its actual state to the environmental state. The physical processes involve only thermal and mechanical interaction with the environment which is defined by pressure P0 and temperature T0, respectively.30 Assuming that potential and kinetic energy can be neglected, the physical exergy is expressed by eq 13:
Exergy loss (Exloss) of each individual unit can be calculated by finding the difference between the exergy of input and output streams of this unit:
H2 exergy efficiency (ηExH2) is taken as the ratio of the total exergy content in H2 product to the chemical exergy of the coal feed:
3.1. Comparison of CLC Process with Physical Absorption and Adsorption Processes for Only Electricity Generation Cases. The net electrical efficiency and CO2 captured shown in Tables 5 and 6 are the two main investigated parameters, which are discussed in this section to compare CLC, PSA, and Selexol based capture technologies. The simulation results of the CLC process that produces only electricity (case 5) give an overall electrical efficiency of 38.7%, which is close to what is observed by a previous study.32 The PSA (case 1) and Selexol (case 2) based processes showed an overall electrical efficiency of 37.4 and 36.4%, respectively, which is lower than case 5. The electrical efficiency achieved for case 5 is also found to be substantially higher as compared with amine-based postcombustion capture technology, which has efficiency between 26.7 and 35.3%.33 The overall CO2 capture efficiency of the CLC process is 99.9% compared with 89.9% for PSA and 93.5% for Selexol processes. This lower overall capture efficiency of PSA and Selexol process is mainly due to the following reasons: (i) the 98% CO conversion efficiency of WGS reactors compared to 99.99% conversion in the CLC fuel reactor and (ii) 90.3% CO2 capture efficiency for the PSA and 95.0% for Selexol units, compared to the assumed complete capture by CLC. The unconverted CO from the WGS reactor is oxidized in a combustor after the CO2 removal step in the presence of air to produce CO2. This CO2 along with the uncaptured CO2 from the CO2 removal unit is expanded in a GT before it is finally vented to the atmosphere with the other flue gases.8
Table 5. Plant Performance Indicators for Cases Producing
Table 6. Amount of CO2 Captured Per Unit Energy and Efficiency Penalty for Cases 1, 2, and 5 with Reference to the Base Case
Figure 2. (a) Relation between electricity production and CO2 emissions for cases 0, 1, 2, and 5 and (b) relation between power production, power consumption and net power output for cases 0, 1, 2, and 5.
Figure 2a shows the variation in electricity production and carbon emissions for all the three different CO2 capture cases with electricity production only. Compared with the CLC process (case 5) that emits 0.0006 t/MWh of CO2 at an emission rate of 0.28 t/h, the PSA (case 1) and Selexol (case 2) technologies emit 0.079 and 0.051 t/MWh of CO2 at an emission rate of 33.6 and 21.1 t/h, respectively. Figure 2b shows a comparison between cases 0, 1, 2, and 5 for gross power output, power consumption, and net power produced. CLC process (case 5) produces less power from the GT unit, but it generates more power from the steam turbines, which results in more net electricity production (436.9 MW) compared with case 1 (421.1 MW) and case 2 (409.6 MW).
3.2. Comparison of CO2 Capture Cases (Cases 1, 2, and 5) Producing Only Electricity with the Base Case (Case 0). Table 5 shows the results of case 0, which is taken as a base case that produces only electricity without any CO2 capture. In case 0, the syngas stream from the WGS reactors is supplied to the combustor unit eliminating the CO2 scrubbing step. The unconverted CO, and H2 from the WGS reactor unit are oxidized in the combustor in the presence of air. The product stream from the combustor is expanded through the GT and sent to HRSG before it is finally vented to the atmosphere. The base case has a higher net electrical efficiency of 41.4% compared to the other cases (cases 1, 2, and 5), which produce only electricity with CO2 capture. Figure 3 shows that case 2 using the Selexol process suffers the highest net energy penalty of 57.2 MW versus case 0 compared to 29.9 MW for CLC and 45.7 MW for PSA-based processes. The results from Table 6 indicate that per MW decrease in energy production compared to the base case, the CLC process captures significantly higher CO2 (9.3 t/h) compared to PSA (5.3t/h) and Selexol (4.5 t/h) process. The relative decrease in the net electrical efficiency in comparison to base case (case 0) for precombustion based capture processes (case 1 and 2) is lower than the energy penalty of 20−29% for the amine based postcombustion capture methods described in a report of the IEA.33
Figure 3. Energy and efficiency penalty in cases 1, 2, and 5 with reference to the case 0.
3.3. Energy Consumption in CO2 Compression for Cases 1, 2, and 5. Table 7 shows the energy consumption in CO2 compression work for PSA, Selexol and CLC processes. It can be seen that the CLC process (case 5) requires only 10.2 MW for compressing 278 t/h of CO2 whereas the IGCC with PSA (case1) and IGCC with Selexol (case 2) processes require 26.3 MW and 29.9 MW, respectively, even though they compress less CO2 compared to the CLC. This is due to the fact that the CO2 stream available for compression in this CLC process is already at elevated pressure levels of approximately 30 atm, and therefore, less energy is required for compressing CO2 to 150 atm. On the other hand, the CO2 streams available for compression in the cases of the PSA and Selexol processes are very close to atmospheric pressure, which explains the higher compression energy requirement for these two technologies. Further analysis can be made to consider the CO2 stream being produced from the system at a pressure of 1 atm. For cases 1 and 2, this would mean that the CO2 compression step is eliminated. In case 5, this analysis assumes that the pressurized (30 atm) CO2 stream from the fuel reactor is expanded in an expander, which will produce an extra 5.11 MW of power. As shown in Table 7, the CLC process will still be more energy efficient than the Selexol and PSA processes and attain a net electrical efficiency of 40.0%. Some consider that this analysis could be useful if the CO2 captured from the power plant were to be used in other industries, instead of sequestration. For example, the food and chemical sectors may have no need for compressed CO2. However, very few processes other than enhanced oil recovery (EOR) and potentially the production of urea are likely to be able to utilize a significant fraction of the CO2 produced by a gasifier producing 467 MWe.
Table 7. Comparison of CO2 Compression Work for Cases 1, 2, and 5
3.4. Comparison of CO2 Capture Technologies for Combined Electricity and H2 Production Cases. One of the main objectives of this work was to investigate the suitability of the gasification-coupled CLC process (case 6) compared to IGCC with PSA (case 3) and Selexol (case 4) technologies for combined electricity and H2 generating plants. Table 8 summaries the results of these cases for identical H2 production rates (524 MW) from each process. Case 6 with CLC yields an overall energy efficiency (59.4%), which is marginally higher than case 4 Selexol (59.1%). Case 6 has a lower overall efficiency compared to the case 3 PSA (60.0%) process owing to two main reasons: (i) lower GT inlet temperature of 727 °C compared to 1185 °C for case 3 and (ii) higher power consumption by the air compressor in air reactor. Figure 4 shows the trade-off between the electrical, H2 and overall efficiencies for case 6. The overall efficiency increases with the H2 production rate whereas the electrical efficiency shows an opposite trend. The decrease in electrical power is the result of less H2 being available for combustion in the GT combustor unit. The H2 produced in the steam reactor of the CLC system can be used for electricity generation during periods of high electricity demand by simply burning it in a separate combustor and expanding through the GT along with the hot air reactor exhaust. This can provide flexibility to the CLC system with respect to changing loads.
Table 8. Plant Performance Indicators for Cases with Combined Electricity and H2 Production
Figure 4. Variation of electrical, H2, and overall efficiency versus the H2 output for case 6.
3.5. Exergy Analysis of PSA, Selexol, and CLC Technologies. Tables 5 and 8 show the results of exergy analysis for all the seven cases. The study indicates an overall exergetic efficiency of 53.6% for case 3 with the PSA process producing combined electricity and H2, which is the highest among all the seven cases analyzed here. The other two cases for electricity and H2 production using Selexol (case 4) and CLC (case 6) process have exergetic efficiencies of 52.7 and 53.0%, respectively. The exergetic efficiency of CLC process is higher compared to Selexol and PSA processes in cases with electricity production only. It is also seen that the captured CO2 stream contains 7.5−10.2% of the total chemical exergy of the coal used as the fuel to the system. If this exergy of the captured CO2 stream is considered to recognize the effort dedicated to CO2 capture, it would make the CLC process more exergetically efficient among the cases with combined H2 and electricity production.
3.6.Effect of Using N2 Available from ASU in GT on 2 Power Output. All the configurations with CO capture, represented by cases 1−6, assumed that N2 from the ASU is added to the feed to the GT unit to enhance its power output. The N2 stream produced in the ASU is compressed (22 atm for the cases without CLC process and 32 atm for CLC) and supplied to the combustors (in cases without CLC) and to the air reactors (in cases with CLC) eventually for expansion through the GT/air turbine.
Figure 5. Effect of ASU integration on power output for cases 1−6.
Figure 5 shows that all the processes benefit, in terms of their power output, from the integration of ASU with the GT unit. The gasification-coupled CLC process (cases 5 and 6) is least effected by ASU integration. In contrast, case 1 experiences 4.7% increase in the net electrical efficiency which is the highest among all six cases. The results show that integrating N2 stream with the GT cycle can improve the overall electrical efficiency of the process despite the extra work required for N2 compression.
Potentially, further integration can be done to use the air from the more efficient compressor of the GT power cycle to supply compressed air to the ASU. This type of integration can completely eliminate the low efficiency ASU compressors.34 A GT compressor can supply HP air to the ASU. The main limitation of such integration is that the ASU cannot start unless the GT starts running. This problem can be resolved by using a separate air compressor for the ASU to start up the process.
3.7. Effect of Air Reactor Temperature on the Power Output of the CLC-Based Process. With the model of gasification-coupled CLC (case 5), the effect of change in air reactor temperature on the net electric power produced has been analyzed. Figure 6a shows that the net power production increases with the air reactor temperature. The power is produced in the GT unit, which is supplied with hot exhaust from the air reactor, and in the steam turbine unit. Steam is generated by the HRSG unit which recovers heat from the hot exhaust of the fuel reactor and that of the gas turbine. The air reactor regulates its temperature via the amount of excess air supplied to the reactor beyond what is required by complete combustion. Figure 6a shows that as the temperature of the air reactor increases, both the power from the stream turbine unit and that from the GT unit increase.
The exhaust gases from the air reactor are expanded through the GT, which gives a higher yield when operated at a higher temperature range. This provides the explanation behind the increase in GT power output with air reactor temperature. When the air reactor is maintained at higher temperature, the temperature of OC supplied to the fuel reactor from the air reactor is also high and hence is higher the fuel reactor temperature. This means a high temperature fuel reactor exhaust is available in the HRSG for steam generation, explaining the reason behind the gain in steam turbine power output with increase in air reactor temperature.
3.8. Effect of Water-Cooling of the CLC Air Reactor on the Power Output. The CLC system (case 5) was examined for the effects of using water-cooling of the air reactor instead of excess air supply as an alternative to maintain the required temperature of 1300 °C throughout the study. The HP water after absorbing heat from the air reactor is converted into HP steam, which is used for power generation. It has been found from the sensitivity analysis that an excess air supply of 81.14% can maintain the desired air reactor temperature without requiring any cooling by water. Figure 6b indicates that the use of water-cooling results in decrease in the feed to the GT, gross, and net power output of the system, whereas the steam turbine output power increase due to more steam available for the steam turbines. Completely using water/steam cooling for the air reactor can decrease the net power output by ∼5.7%. However, this can help in reducing the size of the air reactor, compressor, gas−solid separator, and GT, and hence, the capital cost of the plant.
4. SUMMARY AND CONCLUSIONS
This article investigates the performance characteristics of seven different types of gasification based coal power plants with and without the CO2 capture using PSA, Selexol and CLC processes. Cases 0, 1, 2, and 5 produced only electricity while cases 3, 4, and 6 produced combined electricity and H2.
Figure 6. Effect of (a) air reactor temperature and (b) water-cooling of the air reactor on the power output for CLC process.
All seven process flowsheet models were developed using a chemical process simulation tool “Aspen Plus”. The results generated from the flowsheet simulation models were compared based on the electrical efficiency, H2 production, and CO2 emissions. The effect of ASU and GT integration on the performance of all CO2 capture cases was estimated. Sensitivity analysis was performed for the CLC process to study the plant behavior with respect to air reactor temperature and water cooling of the air reactor.
Among the systems producing only electricity with CO2 capture, the CLC based process achieves the highest electrical efficiency (38.7%) compared with PSA (37.4%) and Selexol (36.4%) based processes. In electricity and H2 cogeneration cases, the CLC-based process has marginally lower (by 0.6%) and higher (by 0.3%) net electrical efficiencies than the PSA and Selexol based process, respectively. However, CLC process can capture 99.9% of CO2 produced, which is potentially higher in comparison to 89.9% for PSA and 93.5% for Selexol based processes. Further comparison among the three capture processes could also be made, based on the cost and life cycle analysis in order to assess the combined techno-economic viability, but such a comparison is beyond the scope of our present study. The ASU and GT integration results in higher power output for all the cases; however, the cases with CLC process have the least effect. The sensitivity analyses performed on CLC process shows that it is favorable to operate the air reactor at higher temperatures for more net power output. Also it has been concluded that cooling of air reactor (while maintaining 1300 °C) by using excess air supply instead of pressurized water tends to increase the net power output of the CLC system.
In addition to the factors considered in the current work, a number of potential improvements will be studied in future investigations. These include extracting and utilizing the heat released by the intercooled compressors, and replacing the cryogenic ASU with membrane-based technology, which can possibly be more efficient when integrated with the GT unit. A detailed sensitivity analysis of the three capture technologies at all different possible operating conditions will be considered in future work to further study and understand the plant behavior in order to assist the optimization of power plants. The CLC process has comparatively more scope of efficiency improve- ment in future by directly using the solid coal fuel into the fuel reactor, eliminating a separate gasification and ASU, which are responsible for high exergy losses in the system.
Source: Sanjay Mukherjee,† Prashant Kumar,*,† Ali Hosseini,‡ Aidong Yang,§,∥ and Paul Fennell⊥
† Department of Civil and Environmental Engineering, Faculty of Engineering and Physical Sciences (FEPS), University of Surrey,
‡ Sharif Energy Research Institute (SERI), Sharif University of Technology, Tehran, Iran
§ Department of Chemical and Process Engineering, FEPS, University of Surrey, Guildford
∥Department of Engineering Science, University of Oxford, Parks Road, Oxford OX1 3PJ
⊥ Department of Chemical Engineering, Imperial College London, South Kensington
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