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Ind. Eng. Chem. Res. 2011, 50, 1674–1690
Steady-State Simulation and Optimization of an Integrated Gasification Combined Cycle Power Plant with CO2 Capture Debangsu Bhattacharyya,*,†,‡ Richard Turton,*,†,‡ and Stephen E. Zitney*,‡ Department of Chemical Engineering, West Virginia UniVersity, Morgantown, West Virginia 26506, United States, and Collaboratory for Process and Dynamics Systems Research, National Energy Technology Laboratory, Morgantown, West Virginia 26507, United States
Integrated gasification combined cycle (IGCC) plants are a promising technology option for power generation with carbon dioxide (CO2) capture in view of their efficiency and environmental advantages over conventional coal utilization technologies. This paper presents a three-phase, top-down, optimization-based approach for designing an IGCC plant with precombustion CO2 capture in a process simulator environment. In the first design phase, important global design decisions are made on the basis of plant-wide optimization studies with the aim of increasing IGCC thermal efficiency and thereby making better use of coal resources and reducing CO2 emissions. For the design of an IGCC plant with 90% CO2 capture, the optimal combination of the extent of carbon monoxide (CO) conversion in the water-gas shift (WGS) reactors and the extent of CO2 capture in the SELEXOL process, using dimethylether of polyethylene glycol as the solvent, is determined in the first phase. In the second design phase, the impact of local design decisions is explored considering the optimum values of the decision variables from the first phase as additional constraints. Two decisions are made focusing on the SELEXOL and Claus unit. In the third design phase, the operating conditions are optimized considering the optimum values of the decision variables from the first and second phases as additional constraints. The operational flexibility of the plant must be taken into account before taking final design decisions. Two studies on the operational flexibility of the WGS reactors and one study focusing on the operational flexibility of the sour water stripper (SWS) are presented. At the end of the first iteration, after executing all the phases once, the net plant efficiency (HHV basis) increases to 34.1% compared to 32.5% in a previously published study (DOE/NETL-2007/1281; National Energy Technology Laboratory, 2007). The study shows that the three-phase, top-down design approach presented is very useful and effective in a process simulator environment for improving efficiency and flexibility of IGCC power plants with CO2 capture. In addition, the study identifies a number of key design variables that has strong impact on the efficiency of an IGCC plant with CO2 capture. Introduction Meeting the challenge of delivering clean, affordable, and secure electric power is critical to sustaining the growth and prosperity of human society. With continued focus on the use of cheap and abundant coal resources for electric power generation, this compound energy challenge shifts to that of reducing greenhouse gas emissions, most importantly carbon dioxide (CO2). Coal-fired power stations contribute about 20% of the worldwide CO2 emissions arising from the utilization of fossil fuels.2 While the fossil energy industry continues to improve the environmental performance of conventional pulverized coal (PC) combustion power plants, advanced technologies such as coal gasification offer the potential to generate significantly lower levels of CO2 and other criteria air pollutants at a lower cost of electricity.3-5 Compared to PC power plants, integrated gasification combined cycles (IGCC) also produce smaller volumes of solid wastes,6use 30-60% less water than the competing technologies,3 provide greater fuel flexibility,3,7and offer attractive polygeneration options.8,9 In addition, the penalty in efficiency and cost of electricity due to CO2 capture is less for IGCC systems compared to conventional PC technologies.1,10 For example, a recent study1 shows that the net plant efficiency (HHV basis) of an IGCC power plant with a general electric * To whom correspondence should be addressed. E-mail:
[email protected] (D.B.); Richard.Turton@ mail.wvu.edu (R.T.);
[email protected] (S.E.Z.). † West Virginia University. ‡ National Energy Technology Laboratory.
energy (GEE)-type gasifier is reduced from 38.2% to 32.5% for 90% CO2 capture, whereas the efficiencies of subcritical and supercritical PC plants decrease from 36.8% and 39.1% to 24.9% and 27.2%, respectively. Another study11 claims that 75% of CO2 from an IGCC plant can be captured with only about 4% loss in efficiency. In recent years, a number of researchers has used steadystate simulation and analysis tools to evaluate IGCC plant performance and efficiency, including the impact of different CO2 capture technologies.12-18 When comparing capture options, appropriate importance must be given to the efficiency, reliability, and cost of not-currently available technologies. For example, some of the capture technologies presented in the existing literature such as semiclosed cycles12,16 and the Matiant cycle14 use CO2 as a working fluid in the gas turbine and will require development of modified gas turbines. Several IGCC studies17,19,20 have also shown that improved system integration can increase overall plant efficiency. In another recent IGCC study, Gnanapragasam et al.21 evaluated the effects of different feedstocks, gasifier inlet conditions, and gasifier temperatures on system performance and CO2 emissions. For an IGCC plant without CO2 capture, Emun et al.22 carried out a sensitivity analysis to determine the impact on system thermal efficiency and environmental performance resulting from variations in the solids concentration in the coal slurry feed, gasification temperature, gas turbine inlet temperature, and level of nitrogen (N2) injection into the gas turbine. Emun et al.22 also applied pinch analysis for heat integration and analyzed the effects on
10.1021/ie101502d 2011 American Chemical Society Published on Web 12/27/2010
Ind. Eng. Chem. Res., Vol. 50, No. 3, 2011
Figure 1. Optimization-based design approach of an IGCC plant with CO2 capture in a process simulator environment.
overall IGCC plant efficiency. While these studies used steadystate simulation and analysis tools, they did not consider optimization for improving the efficiency and flexibility of IGCC power plants with CO2 capture. Bahri et al.23,24 presented a two-level iterative approach for optimal design of chemical processes. In the first level, the optimal plant design and operating conditions (and control structure) are obtained by solving a mixed-integer nonlinear programming (MINLP) problem. In the second level, a NLP problem is solved for investigating the feasibility of the solution obtained in the first level. This approach, though rigorous, has a number of drawbacks for a process simulator. First, many process simulators do not have algorithms for constrained nonlinear optimization. Second, as each of the steps requires solution of an optimization problem that is an iterative procedure, the problem can become computationally intractable for a plant-wide simulation. It should be noted that our current model of the IGCC plant with CO2 capture contains more than 120 000 equations. Third, when optimization is done in a flowsheet that involves a number of recycle streams, the solution becomes very difficult, especially with a sequential modular approach typical of process simulators. The SELEXOL unit is a good example of a unit involving multiple recycle streams. Fourth, the optimization may involve integer decision variables as in the first level of the approach proposed by Bahri et al.23,24 Process simulators typically do not offer algorithms for solving mixed integer programming problems. The present study describes a three-phase, top-down, optimization-based design approach as shown in Figure 1. Each of the phases may have subphases, if needed. The optimization at each phase/subphase can be done by sensitivity studies or by rigorous optimization based on the available algorithms in the chosen simulator envionment. The optimum values of the decision variables from each phase are treated as constraints in the next phase. If a phase/subphase involves integer variables, then that phase/subphase is solved by a case-study approach where a finite set of options is considered and then the optimum of each option is compared. A number of examples that involves integer variables can be found in the second design phase of this study. This approach provides the flexibility of the use of
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a combination of sensitivity studies and rigorous optimization that may involve integer decision variables. In the top phase of the optimization hierarchy, important global (plant-wide) design decisions aimed at maximizing net energy efficiency are evaluated considering limits and/or targets on environmental emissions. Because the focus of this paper is on CO2 capture, a study is done by varying the percent conversion of carbon monoxide (CO) in the water-gas shift (WGS) reactors and percent capture of CO2 in the SELEXOL unit to maximize plant efficiency while achieving the target of 90% carbon capture for the overall system. In the second design phase, local design decisions are made considering the integer decision variables. In this phase, the optimum values of percent conversion of carbon monoxide (CO) in the WGS reactors and percent capture of CO2 in the SELEXOL unit from the first phase are considered as additional constraints. The first study on local design decision evaluates the use of a single stage flash vessel as the H2S concentrator in the SELEXOL unit compared to a multistage stripper. Another local design study compares the technical feasibility and impact on energy efficiency of routing the tail gas from the Claus unit to the H2S absorber in the SELEXOL unit against sending it directly to the CO2 compression unit. In the third phase, the operating conditions are optimized subject to the additional constraints from the first and second phases. Two studies are presented. In the first study, the flow rate of the stripping medium in the H2S concentrator is optimized. In the second study, the pressures of the flash vessels in the SELEXOL unit are optimized to reduce the power consumption in the SELEXOL and CO2 compression unit. Before the final design decisions are taken, an assessment of the operational flexibility should be done. This ensures that a certain desired level of performance is achieved in face of disturbances and uncertainties. Two studies on the operational flexibility of the WGS reactors are done. Both the studies consider that there is a desired upper limit on the amount of steam extracted from the steam turbine (ST). As the supplemental steam in the WGS reactors is provided by extracting steam from the ST, a larger extraction results in a loss of power from the ST affecting the overall plant efficiency. In the first design phase, the optimum conversion of CO in the WGS reactors is determined for maximizing the plant efficiency. However, it may be desired to vary the CO conversion in the WGS reactors for a flexible CO2 capture scenario. The first study evaluates the effect of this scenario on the amount of steam extracted from the ST. The second study evaluates the effect of change in the syngas carbon-to-hydrogen and CO2/CO ratios on the amount of steam extraction from the ST. Another study on the operational flexibility of a sour water stripper (SWS) considers a desired level of 50 ppmw NH3 in the stripped condensate. In this paper, each phase of the proposed top-down design approach is executed once using representative optimization studies focused largely on maximizing the net power generated from the IGCC plant with CO2 capture. This iterative procedure should be repeated as shown in Figure 1 until some convergence criteria are satisfied. After that, an assessment of operational flexibility should be done. If found unsatisfactory, the steps should be repeated. The convergence criteria can simply be based on a user defined tolerance on absolute or relative differences between the current and old values of the operating conditions in addition to satisfying the criterion that the design decisions taken in the second phase are unchanged compared to the previous iteration. Other user defined convergence criteria can also be considered. Since each phase is executed only once in generating the results presented in
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Figure 2. Layout of the IGCC with CO2 capture.
the “Results and Discussions” section, the results should not be treated as the final IGCC design. It should be noted that this paper proposes a generic approach that can be applied over a wide range of commercial steady-state simulators. If certain features (algorithms) are available in a software platform, the user can utilize that to develop a more systematic approach. For example, the user, instead of doing a sensitivity study, can find out the decision variables for an optimization study by generating a gain matrix and then considering the appropriate decision variables for carrying out a nonlinear constrained optimization. It should also be noted that the present work does not consider changes in the configuration of the IGCC plant (except where mentioned) and does not take equipment capital cost into account. For an optimal technoeconomic design, multiobjective optimization with potential topological changes and consideration of other available technologies should be considered. Plant Configuration The selection of gasification technology for IGCC depends on various factors such as the quality of the feed coal, capital investment, efficiency goals, reliability, availability, cost of electricity, environmental targets, and CO2 capture technology.1,6,25 The general electric energy (GEE) entrained-flow gasifier, previously the Texaco technology, currently holds a strong position with about 34% of the world’s gasification capacity, including the Tampa Electric (TECO) IGCC power generation facility.26 In this paper, a single-stage, oxygen-blown, GEE-type entrained-flow slagging gasifier with radiant syngas cooler is considered. For gasification-based power plants, a number of precombustion CO2 capture techniques is being explored with promising results.25,27-29 In this paper, CO shift conversion followed by physical absorption is used on the basis of the maturity of the technology and because of the high partial pressure of CO2 from a GEE-type gasifier. Physical absorption is also very efficient and the least capital-intensive CO2 capture technology that is commercially proven.27,30 Because of a number of advantages such as lower solvent loss, higher selectivity toward H2S, better thermal stability, better water solubility, and lower circulation
rate,31-33 dimethylether of polyethylene glycol (SELEXOL) is the physical solvent considered in this study. A techno-economic analysis shows that a SELEXOL-based CO2 capture process is very competitive compared to membrane reactors and chemical looping processes.34 The IGCC with CO2 capture plant configuration used as the base case for the present study is shown in Figure 2 and is a modified version of the Case 2 configuration described in a recent fossil energy power plant cost and performance comparison by the National Energy Technology Laboratory (NETL).1 The coal slurry is fed to an oxygen-blown GEE-type gasifier with radiant-only configuration. The hot syngas exiting the gasifier passes through a radiant syngas cooler (RSC) and a water scrubber. The scrubbed syngas is shifted in two WGS converters. The shifted syngas is further cooled before going to the acid gas removal (AGR) process which is a physical absorption process with SELEXOL solvent. The sour water drained from the syngas coolers is sent to the syngas treatment unit. The clean water from the sour gas treatment unit is sent to the scrubber and is for slurry preparation. In the first stage of the dual-stage SELEXOL unit, H2S is separated in the stripper and sent to the Claus unit. In the second SELEXOL stage, CO2 is separated and sent to the compression unit for sequestration. Following the AGR process, the cleaned syngas is heated and expanded before going to the gas turbine combustor where diluent N2 from the ASU is mixed. The hot flue gas from the gas turbine flows through a heat recovery steam generator (HRSG). In the HRSG, a triple pressure steam cycle generates high pressure (HP), intermediate pressure (IP), and low pressure (LP) steam. IGCC Steady-State Modeling and Simulation Approach In this section, the steady-state modeling and simulation of the coal-fired IGCC plant with CO2 capture is discussed. First, the coal analysis and handling is described. Next, the IGCC plant is divided into a number of major, well-defined areas including gasification, radiant syngas cooler and scrubber, shift converters and syngas cooling, sour water stripper, SELEXOL unit and CO2 compression,
Ind. Eng. Chem. Res., Vol. 50, No. 3, 2011 Table 1. Proximate Analysis of Illinois No. 6 Coal (Dry Basis)
Table 3. Restricted Equilibrium in the Gasifier
value (dry basis) moisture FC VM ash HHV (kJ kg-1)
11.12 49.72 39.37 10.91 30506
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no.
reaction
temperature approach to equilibrium (°C)
1
C + O2 f CO2
0
2
C + 0.5O2 f CO
0
3
H 2 + S f H 2S
0
4
H2O + CO f CO2 + H2
-480
5
CH4 + H2O f 3H2 + CO
-50
6
N2 + 3H2 f 2NH3
-700
7
COS + H2O f CO2 + H2S
-650
Table 2. Ultimate Analysis of Illinois No. 6 Coal (Dry Basis) value (dry basis) ash carbon hydrogen nitrogen sulfur oxygen
10.91 71.72 5.06 1.74 2.82 7.75
Claus unit, gas turbine and the heat recovery steam generator (flue gas side), steam cycle, and air separation unit. All these IGCC plant areas are modeled using the commercial steady-state process simulator, Aspen Plus Version 2006.5.35 Coal Analysis and Handling. In this study, the primary feed to the IGCC plant is Illinois No. 6 bituminous coal, characterized by the proximate analysis and ultimate analysis provided in Tables 1 and 2, respectively. These coal properties are similar to those for the Illinois No. 6 #1 coal used in tests run at the IGCC power plant at Polk Power station operated by Tampa Electric Company (TECO).36 As a result, the TECO project status report36 is used as the basis for specifying operating points and ranges for sensitivity studies for many of the IGCC equipment items described in this work. The coal analysis data in Tables 1 and 2 are used to “decompose” the Illinois No. 6 coal into the following species: C, H2O, H2, N2, S, O2, and ash. Ash is characterized as silicon dioxide (SiO2) and “converted” to slag in a stoichiometric reactor (RStoic model in Aspen Plus). The stoichiometry of the reaction in the RStoic model is manipulated so that all of the ash and 2% of carbon are removed in the slag assuming 98% carbon conversion in the gasifier. The “decomposed” coal with slag removed is then fed to the gasifier. Gasifier. The entrained-flow GEE-type gasifier considered in this paper is modeled as a restricted chemical equilibrium reactor with temperature approaches to equilibrium for individual reactions. Using a more simplistic approach, some authors have assumed that the syngas at the gasifier outlet exists at chemical equilibrium, which is reasonably accurate if the carbon conversion in the gasifier is properly considered and the gasifier operating temperature is known.37,38 Carbon conversion is one of the most important parameters for measuring the gasifier performance and depnds on a number of factors.39-42 In this study, the carbon conversion in the gasifier is specified to be 98% based on the TECO results for Illinois No. 6 #1 coal.36 The restricted-equilibrium gasifier reactor model (RGibbs model in Aspen Plus) used in this work minimizes Gibbs free energy considering the reactions shown in Table 3. The reaction temperature approaches shown in Table 3 are specified to match the experimental/industrial data for the GEE-type entrainedflow gasifier using Illinois No. 6 coal and operating at a temperature of 1315.6 °C and pressure of 5.61 MPa.1 As some of the reactions, such as the WGS reaction, continue in the RSC and the current RSC model does not consider any reaction, the temperature approach in the gasifier has been utilized to capture this phenomenon. Since the GEE-type gasifier is a slagging gasifier, its operating temperature must be high enough to ensure free slag flow along the wall and avoid clogging at the bottom of the gasifier. Wide variations in the ash fusion temperature
of various types of Illinois No. 6 coal have been reported.43 The data from the test runs conducted at TECO IGCC plant show that the T250 temperature of the ash from the two types of the Illinois No. 6 coal are 1360 and 1326 °C, respectively.44 Therefore, the operating temperature of 1315.6 °C is reasonable for the desired slag viscosity and carbon conversion. It should be noted that higher operating temperatures can reduce the refractory life for GEE-type gasifiers. In this study, the gasifier dimensions have been calculated maintaining the same superficial velocity as that reported for the TECO gasifier.44,45 For calculating the heat loss from the gasifier, both the radiative and convective heat losses have been considered. An infrared image of a GEE-type gasifier shows skin temperature of about 175-200 °C.46 A uniform skin temperature of 200 °C is assumed in this study. In addition, a wind velocity of 8 km hr-1 and ambient temperature of 25 °C is assumed. The heat loss from the gasifier is found to be about 0.65% of the HHV of the coal. For the simulations in this work, the O2/wet coal ratio is manipulated so that the gasifier temperature is maintained constant at 1315.6 °C while taking into account the heat loss at the conditions mentioned previously. For steady-state gasifier models in Aspen Plus, coal can be declared as a nonconventional solid component characterized in terms of the component attributes ULTANAL (ultimate analysis) and PROXANAL (proximate analysis). However, it should be noted that unit operation models involving solids in Aspen Plus Version 2006.5 cannot be exported automatically to Aspen Plus Dynamics. Even though it is possible to model unit operations involving solids in Aspen Plus, it is not yet possible to export that model to Aspen e outlet from the first reactor is cooPlus Dynamics. In view of this limitation, Robinson and Luyben45 have used a complex cyclical aromatic as a surrogate compound for coal. In the future, the plant-wide steady-state IGCC model developed as part of this study will be exported to Aspen Plus Dynamics for use in transient studies. In view of this, all the nonconventional components are declared as conventional components using electrolyte chemistry. Since salt is the only solid component currently handled in Aspen Plus Dynamics, the nonconventional solids in the Aspen Plus IGCC model developed in this study are treated as salts by setting up chemistry of type “salt”. The equilibrium constants are manipulated such that the equilibrium completely favors the salt. For the gasification section, the selected property method is the “ELECNRTL” option which uses the Redlich-Kwong equation of state. In summary, the electrolyte chemistry ap-
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Figure 3. Configuration of the gasifier, syngas cooling, shift reactors, and the blackwater treatment units.
proach not only generates comparable results to the case where nonconventional solid components are used but also enables the automatic export of the plant-wide IGCC model from Aspen Plus to Aspen Plus Dynamics. Radiant Syngas Cooler (RSC) and the Scrubber. As shown in Figure 3, the gasifier outlet goes to the RSC where it is used to generate HP steam from the boiler feedwater (BFW) coming from the HRSG economizer at a pressure of about 13.58 MPa. The outlet temperature of the syngas leaving the RSC is fixed at 599 °C. The saturated steam from the RSC steam drum is sent to the HRSG superheater. The heat loss from the RSC is calculated by considering both radiative and convective heat losses. Slag is separated from the syngas in a “flash” separator. The syngas from the top of the slag separator goes to the scrubber. The scrubber is simulated as a flash vessel where the amount of quench water is manipulated by a design specification (called “designspec” in Aspen Plus) to decrease its temperature to 210 °C. Shift Converters and Syngas Cooling. The two water-gas shift (WGS) reactors in series are modeled as adiabatic plug flow reactors. The WGS reaction is a reversible reaction and is given by CO + H2O S CO2 + H2
(1)
The kinetics are taken from the open literature for a sour shift catalyst.47,48 The forward rate for “Catalyst # N” which is a “halfstrength” cobalt molybdenum-based catalyst is given by eq 2.
( )
-rf ) 2.6 × 104exp -
Ef kmol [CO] 3 RT ms
(2)
where Ef ) 53172 (kJ)/(kmol) and [CO] is molar concentration of CO in (kmol)/(m3s). The rate parameters in eq 2 were derived under nearatmospheric condition.47,48 The authors could not find any rate expression for the sour shift catalysts in the open literature that has been validated with experimental data at the operating pressure considered in this study. The equilibrium constants are given49 by eqs 3 and 4 for the high temperature reactor (the first reactor) and the low temperature reactor (the second reactor), respectively.
8240 for1060 e T e 1360 ( T ) 8640 ) exp(-4.72 + for760 e T e 1060 T )
Keq ) exp -4.33 +
(3)
Keq
(4)
where T ) temperature, °R. The sizing of the reactors, the quantity of the catalysts, and the pressure drop across the reactors have been determined following the work of Rase.49 It was ensured that the operating temperatures of the reactors remain in the range of 215-500 °C.47,48,50 In addition, the minimum temperature at the inlet is maintained at 25 °C above the dew point. The outlet from the first reactor is cooled to 355 °C by raising a part of the shift steam. The syngas is further cooled to 241 °C by generating IP steam before it is sent to the second reactor. The second reactor outlet is cooled by raising IP steam that is reheated along with the exhaust from the HP steam turbine and used in the IP section of the steam turbine. Shifted syngas is further cooled in four exchangers with intermediate flash drums before going to the SELEXOL unit. In the first exchanger, it is cooled to 168 °C by generating IP steam. After that, syngas is cooled to 122 °C by heating up the BFW. In the third exchanger, syngas is used to heat the makeup water for the scrubber. Finally, syngas is cooled by the cleaned syngas leaving the CO2 absorber in the SELEXOL unit. The process condensate streams from the first through last flash vessels, containing about 798, 1402, 3821, and 25949 ppm of NH3, respectively, are sent to the SWS. Sour water Stripper (SWS). Sour water stripping has been a subject of study for a long time.51-53 However, little information is available in the open literature about the impact of the design of a sour water stripper (SWS) in an IGCC plant. The SWS plays a key role in generating water that can be recycled back to the gasifier and is a major consumer of stripping steam. Operation of the SWS is also one of the problematic areas in an IGCC plant.44 In this simulation, approximately 5% of the bottom effluent from the scrubber is sent to the SWS as purge. The remainder of the bottom effluent is sent to a flash block. The vapor from the flash block is sent to the SWS. The liquid from the flash block is recycled back to the scrubber. As mentioned above, the process condensate from the syngas coolers is also sent to the SWS. The condensate from the tail gas (TG) compressor
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Figure 4. Configuration of the SELEXOL unit and the CO2 compression section.
suction knockout (KO) drum and TG interstage condensate is drained to the SWS. In Aspen Plus, a rigorous distillation column (RadFrac) is used to simulate the SWS. The following reactions are considered 2H2O S H3O+ + OH-
(5a)
H2S + H2O S H3O+ + HS-
(5b)
HS- + H2O S H3O+ + S--
(5c)
CO2 + 2H2O S H3O+ + HCO3-
(5d)
HCO3- + H2O S H3O+ + CO3--
(5e)
NH3 + H2O S NH4+ + OH-
(5f)
NH3 + HCO3- S NH2CO2- + H2O
(5g)
The electrolyte nonrandom two liquid (NRTL) activity coefficient model is used for liquid phase physical property calculation. The Soave-Redlich-Kwong (SRK) equation of state (EOS) is used for the vapor phase. SELEXOL Unit and CO2 Compression. Different configurations of the SELEXOL unit can be considered on the basis of the design objective and the available integration opportunities.54 In this work, the dual-stage SELEXOL unit, as shown in Figure 4, is configured for selective removal of H2S (first stage) and CO2 (second stage) from the sour syngas using dimethylether of polyethylene glycol (DEPG) as a solvent. Most of the H2S in the syngas is absorbed in the semilean solvent as it passes through the H2S absorber. The tail gas (TG) from the Claus unit (Figure 5) is also recycled to the H2S absorber. The condensate from the TG compressor interstage KO drums is sent to the SWS. The off-gas from the top of the H2S absorber is sent to the CO2 absorber. Clean syngas from the CO2 absorber
exchanges heat with the incoming sour syngas to the H2S absorber and is then heated before going to the expander (Figure 6). A portion of the loaded solvent (about 30% in the base case) from the bottom of the CO2 absorber is cooled in a water cooler, chilled, and sent to the H2S absorber. The rich solvent from the bottom of the H2S absorber is heated by exchanging heat with the lean solvent from the stripper. Thereafter, the syngas goes to a flash vessel. The vapor from the flash vessel is recycled back to the H2S absorber. The bottom stream from the flash vessel goes to the SELEXOL stripper which uses a combination of stripping steam and a reboiler for deep removal of H2S from the syngas. Make-up solvent is mixed with the stripped solvent and sent to the top tray of the CO2 absorber. The remaining portion of the loaded solvent from the bottom of the CO2 absorber is heated and sent through a series of four flash vessels to recover CO2 for compression in preparation for storage. The loaded solvent stream is first heated by exchanging heat with the recycled solvent from the exit of the LP flash vessel and then further heated by a small LP steam heater. Next, the loaded solvent flows through the first flash vessel, generally called the H2 recovery drum, which operates at about 3/4 of the pressure of the CO2 absorber in order to recover about 75% of the H2 dissolved in the solvent. More specifically, the pressure of the H2 recovery drum is adjusted such that the sequestered CO2 contains about 0.7 mol % of H2. This H2 concentration level is easily achieved using the IGCC configuration and simulation in this study. The recommended design basis for CO2 sequestration gas from NETL (Table 4) shows the limit on H2 content to be uncertain at this time. On the basis of future specifications, the H2 concentration can be increased or decreased by adjusting the pressure of the H2 recovery drum. Upon removing the absorbed H2, the solvent stream then goes through three additional flash vessels, high pressure (HP), medium pressure (MP), and low pressure (LP), to release CO2. Approximately 49.3%, 19.7%, and 25.3% of CO2 dissolved in the solvent is recovered in the HP, MP, and LP flash vessels, respectively, in the base case. The semilean solvent leaving the
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Figure 5. Configuration of the Claus unit.
Figure 6. Configuration of the GT and the HRSG (flue gas side). Table 4. Recommended Design Basis for the CO2-Sequestration Gas for a Remote, Deep, Geological Storage Site55 final pressure
15.16 MPa
H2O N2, NH3, CO H2S CH4 H2 SO2
0.015 vol % not limited
