Improved System Integration for Integrated Gasification Combined

Feb 2, 2006 - A process simulation model was developed for IGCC systems with alternative types of ASU and gas turbine integration. The model is applie...
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Environ. Sci. Technol. 2006, 40, 1693-1699

Improved System Integration for Integrated Gasification Combined Cycle (IGCC) Systems H. CHRISTOPHER FREY* AND YUNHUA ZHU Department of Civil, Construction, and Environmental Engineering, North Carolina State University, Campus Box 7908, Raleigh, North Carolina 27695-7908

Integrated gasification combined cycle (IGCC) systems are a promising technology for power generation. They include an air separation unit (ASU), a gasification system, and a gas turbine combined cycle power block, and feature competitive efficiency and lower emissions compared to conventional power generation technology. IGCC systems are not yet in widespread commercial use and opportunities remain to improve system feasibility via improved process integration. A process simulation model was developed for IGCC systems with alternative types of ASU and gas turbine integration. The model is applied to evaluate integration schemes involving nitrogen injection, air extraction, and combinations of both, as well as different ASU pressure levels. The optimal nitrogen injection only case in combination with an elevated pressure ASU had the highest efficiency and power output and approximately the lowest emissions per unit output of all cases considered, and thus is a recommended design option. The optimal combination of air extraction coupled with nitrogen injection had slightly worse efficiency, power output, and emissions than the optimal nitrogen injection only case. Air extraction alone typically produced lower efficiency, lower power output, and higher emissions than all other cases. The recommended nitrogen injection only case is estimated to provide annualized cost savings compared to a nonintegrated design. Process simulation modeling is shown to be a useful tool for evaluation and screening of technology options.

Introduction Integrated gasification combined cycle (IGCC) systems are an emerging technology for power generation from coal and other feedstocks. They feature equal or higher efficiency and lower emissions compared to conventional subcritical pulverized coal (PC) combustion power plants that are widely used now in the United States (1-5), and approximately similar efficiency to supercritical PC plants that may be more extensively used in the future (3, 6). IGCC systems also offer greater fuel flexibility and can produce multiple products (7). Figure 1 provides a simple diagram of the major components of an IGCC power plant. An IGCC system includes three process areas: air separation unit (ASU); gasification island; and gas turbine combined cycle. Pressurized high purity oxygen is produced in an ASU and sent * Corresponding author e-mail: [email protected]; tel: (919) 5151155; fax: (919) 515-7908. 10.1021/es0515598 CCC: $33.50 Published on Web 02/02/2006

 2006 American Chemical Society

to a gasifier. In a gasifier, coal or other feedstock reacts with oxygen in the presence of slurry water or steam to produce a syngas rich in carbon monoxide (CO) and hydrogen (H2). The combustible syngas is used to produce electricity in a combined cycle, which consists of a gas turbine, a heat recovery steam generator (HRSG), and a steam turbine. A perceived opportunity for improving IGCC system efficiency, and thus lowering the cost, pertains to the integration of an ASU with a gas turbine by extracting air from the gas turbine compressor for input to the ASU and nitrogen injection from the ASU to the gas turbine combustor (8-12). Air extraction can reduce the ASU power consumption and nitrogen injection can reduce the NOx emissions. Although the ASU and gas turbine integration has been utilized in some IGCC projects (2, 13, 14), there is little assessment of whether the apparent advantages of the combination of air extraction and nitrogen injection can be attributed primarily to either extraction or injection alone. Furthermore, the effects of air extraction and nitrogen injection may depend on the type of ASU, such as low pressure (LP) versus elevated pressure (EP) designs (8, 11-14). The effects of different integration methods are evaluated based on alternative ASU pressure levels with respect to the performance, emissions, and cost of IGCC systems. This work builds upon methods for process simulation and case study applications (15-19). The following key questions are answered: What is the effect of different levels of nitrogen injection on IGCC system performance and emissions?; What is the effect of different percentages of compressor air extraction?; What is the effect of combinations of both air extraction and nitrogen injection?; What is the effect of different ASU designs (e.g., LP vs EP) on IGCC system performance and emissions for a given level of air extraction, nitrogen injection, or both?; What general guidance can be provided regarding recommended approaches for air extraction, nitrogen injection, or both for a typical IGCC system?; and What methods are recommended for assessment of system integration alternatives? To answer these key questions, this paper describes the development of a design basis for IGCC systems with an integrated ASU, a process simulation model developed in ASPEN Plus, and multiple case studies. Key findings and recommendations are developed from the results of the case studies. IGCC demonstration projects with integrated designs are listed in Table S-1 in the Supporting Information (SI).

Design Basis The design basis for an IGCC system with integrated ASU design features either LP- or EP-ASU designs; an entrained flow gasifier; high-temperature gas cooling; low-temperature acid gas separation; syngas reheating and combinations of either moisturization, nitrogen injection, or both; and a “Frame 7F” gas turbine considering various degrees of air extraction. A design basis for an ASU and for the integration of the ASU and gas turbine was developed based on previous design studies (10, 15, 16). Cryogenic air separation is widely used and is assumed as a design basis for ASU (8-10). The LP-ASU has a cryogenic unit pressure of approximately 5 atm, whereas the EP-ASU operates at approximately 10-15 atm (2, 12, 16). Air extraction, nitrogen injection, or both can be used. The EP-ASU is more appropriate for use with air extraction because it operates at a pressure level closer to that of a gas turbine VOL. 40, NO. 5, 2006 / ENVIRONMENTAL SCIENCE & TECHNOLOGY

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FIGURE 1. Simplified process flowsheet for an integrated gasification combined cycle (IGCC) system.

FIGURE 2. Conceptual diagram of integration of air separation unit and gas turbine, including air extraction and nitrogen injection. compressor outlet. In contrast, if an LP-ASU were to be used with air extraction, it would be necessary either to extract air from an intermediate location in the compressor or to reduce the pressure of the air at the compressor outlet, such as with an expander. The former would increase system complexity and the latter would increase system cost and result in an efficiency penalty. Therefore, the EP-ASU is the preferred option for use with air extraction. However, 100% air extraction is not recommended because of difficulties with start-up and loss of operational flexibility (20).

where mair,EX ) mass flow rate of air extracted from the gas turbine compressor (kg/s), and mair,ASU,i ) mass flow rate of ambient air sent to ASU (kg/s). The percentage of nitrogen injected to the gas turbine combustor relative to the total nitrogen produced by the ASU (PNI) is given by

Process Simulation Modeling

where mN2,in ) mass flow rate of nitrogen injected into the gas turbine (kg/s), and mN2,total ) mass flow rate of total nitrogen product from ASU (kg/s). The term “air extraction” is used in this paper to represent the concept of “integration degree” used elsewhere (2, 8, 11). Integration designs are categorized into three types: (1) nonintegrated design where PAE and PNI are both zero; (2) partially integrated design where one of the two is zero; and (3) totally integrated design where both of them are not zero. Criteria for Nitrogen Injection and Moisturization. Both nitrogen injection and moisturization can be used to control NOx formation from a gas turbine (22, 23). Most of the NOx emissions of IGCC plants are from thermal NOx formation (16, 22), which is sensitive to combustion temperature. Dry low NOx combustion systems for modern gas turbines feature diluent injection and premixing with fuel gas. The injection of diluents such as moisture or nitrogen in the syngas and air mixture leads to a reduction in peak flame temperature and, hence, a reduction in NOx emissions (16, 22, 23). Moisture injection and premixing with syngas is assumed based on the specifications of an F class gas turbine (19). In a typical nonintegrated design, moisture is injected to syngas to achieve a moisture content of 28.2 wt % (19). To compare system performance of nonintegrated and integrated designs, the preference is to compare cases based upon constant NOx

To evaluate the effects of different integration methods on the performance, emissions, and cost of IGCC plants, a process simulation model was developed in ASPEN Plus. ASPEN Plus is a FORTRAN-based steady-state chemical process simulator, which can be used to evaluate synthesis fuel technologies (21). An ASU model was developed and combined with a previously developed IGCC model (19). The model was developed to calculate mass and energy balances for an entrained flow gasifier-based IGCC system, to evaluate design modifications, to track environmental species, and to compute capital, annual, and levelized plant cost (19). Integration of the ASU and Gas Turbine. A conceptual diagram of ASU integration with a gas turbine is shown in Figure 2. Air extracted from the compressor is sent to the ASU. Nitrogen from the ASU is injected into the combustor. The percentage of air extracted from the gas turbine compressor, relative to the total air needed by the ASU, (PAE) is given by

PAE ) 1694

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PNI )

mN2,in × 100% mN2,total

TABLE 1. Case Study Results for Nitrogen Injection without Air Extraction (Case A) Based on Integrated Gasification Combined Cycle Systems with LP-ASU and EP-ASU description

Base

A1

A2

A3

A4

A5

A6

A7

PAE, % MN2/Msg PNI, % moisture fraction in syngas, wt % coal feed rate, kg/s nitrogen feed rate, kg/s saturated syngas heating value, Btu/scf, LHVa air to gas turbine, kg/s combustor exhaust flow rate, 103 gmole/s

0 0 0 28.2 24.2 0.0 181.4 430.9 14.5

0 0.15 12.8 22.9 24.1 9.2 192.6 427.1 14.5

0 0.30 25.6 16.6 23.9 18.3 213.6 423.4 14.4

0 0.45 38.4 9.2 23.7 27.2 234.6 419.6 14.4

0 0.604 51.5 0 23.5 36.2 259.1 417.1 14.4

0 0.75 63.9 0 23.6 45.2 259.0 405.7 14.4

0 0.9 76.7 0 23.8 54.6 258.9 394.4 14.4

0 1.15 98.0 0 24.0 70.4 258.8 376.7 14.5

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW nitrogen compressor, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case A: LP-ASU 192.1 192.2 192.3 132.1 135.0 137.9 40.0 43.5 46.8 28.2 28.0 27.8 0 3.4 6.7 284.1 283.7 283.3 39.47 39.69 39.93 862 866 862 771 767 762 1 1.0 1.0

192.3 140.7 50.1 27.6 9.9 283.0 40.16 857 758 1.0

192.3 143.5 53.4 27.4 13.2 282.4 40.42 853 753 1.0

196.7 143.7 57.1 27.5 16.5 283.3 40.37 853 753 0.5

201.3 144.2 61.1 27.6 20.0 284.4 40.28 857 753 0.2

209.2 144.8 67.8 27.9 25.6 286.1 40.15 857 758 0.1

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW nitrogen compressor, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case A: EP-ASU 192.1 192.2 192.3 132.2 135.0 137.9 48.9 50.4 51.8 36.2 35.9 35.6 0 1.7 3.4 275.4 276.9 278.3 38.26 38.74 39.23 898 889 880 794 785 776 1.0 1.0 1.0

192.3 140.8 53.3 35.4 5.0 279.8 39.71 866 767 1.0

192.3 143.6 54.7 35.1 6.7 281.1 40.24 857 753 1.0

196.7 143.8 56.7 35.3 8.3 283.7 40.43 853 753 0.5

201.3 144.3 58.9 35.5 10.1 286.7 40.58 848 748 0.2

209.2 144.9 62.6 35.8 13.0 291.6 40.87 844 744 0.1

a

LHV ) lower heating value.

b

HHV ) higher heating value.

emissions but if necessary (e.g., because of high levels of nitrogen injection) the NOx emissions may decrease versus the baseline. A chemical kinetic model developed by Flagan and Seinfield (24) is used to estimate the thermal NOx formation in the primary combustion zone in a combustor. On the basis of this model, the amount of moisture needed for a given value of PNI is estimated in order to keep a constant NO fraction in the primary combustion zone, where possible. Details are given in the Supporting Information. The features of ASPEN Plus are described in the SI. The specifications and flowsheet of the ASU model are given in Table S-2 and Figure S-1. The calculation of nitrogen injection and moisturization is described in the SI. Verification of the integrated IGCC model demonstrated the model performs well and the results are given in Table S-3.

Case Study Scenarios and Input Assumptions To answer the key questions posed in the Introduction, a base case and three case studies are investigated. The base case is an entrained flow gasifier-based IGCC with radiant and convective cooling and with no nitrogen injection or air extraction. A single Frame 7F gas turbine and a reheated steam turbine are assumed. The fuel is Illinois No. 6 coal. The base case is treated as a benchmark for comparison. Since an LP-ASU is typically used in a nonintegrated IGCC system (2, 8-10), the emissions of NOx per unit output from the nonintegrated LP-ASU is used as the basis for the relative NOx emissions calculation for other cases. The three case studies include: (1) Case A, nitrogen injection only; (2) Case B, air extraction only; and (3) Case C, both nitrogen injection and air extraction. For each case study, a sensitivity analysis is performed regarding the applicable air extraction and nitrogen injection percentages.

The IGCC systems based on LP-ASU and EP-ASU are evaluated individually for each case. In Case A, values of PNI ranging from 0% to 98% are considered. The required amount of moisturization for a specific value of PNI is calculated. When PNI ) 51.5%, the estimated NO emissions are the same as those for the base case without need for moisturization. As the nitrogen injection increases to higher levels, the estimated NO emissions decrease monotonically compared to the base case. PNI ) 98.0% represents the practical upper bound on the total amount of nitrogen available for injection (12). For Case B, PAE is varied from 0% to 50%, and PNI ) 0. The moisture fraction is 28.2%. The typical optimal air extraction is reported to be well below 50% for Frame 7F gas turbines (9, 11). Thus, an upper limit of 50% is selected. For Case C, PAE is varied from 0% to 50%. In this case, only nitrogen injection is assumed to be used for NOx emissions control and moisturization is not used. This assumption is adopted based on (11). When PAE ) 0 and the moisturization is zero, PNI is 51.5% to keep constant NOx emissions level as the Base Case. PNI increases with PAE until the total available nitrogen is used. In this case, the total air flow to the gas turbine is assumed to be constant in order to calculate the PNI based on specific PAE. The key input assumptions for the IGCC model for each case are listed in Table S-4 in the SI.

Results and Discussion In this section, performance and emissions results from the model are summarized and discussed. Base Case. The results of the Base Case are listed in Table 1. Since the EP-ASU has higher air compressor outlet pressure than the LP-ASU, the auxiliary power consumption for the former is higher due to higher ASU compressor power VOL. 40, NO. 5, 2006 / ENVIRONMENTAL SCIENCE & TECHNOLOGY

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FIGURE 3. Effects of changes in nitrogen injection on the plant efficiency of IGCC with LP-ASU and EP-ASU. consumption. Thus, the efficiency for the EP-ASU based system is lower than that of the LP-ASU system. Because of the lower efficiency, the SO2 and CO2 emissions on an energy output basis are approximately 4% and 3% higher, respectively. The relative NOx emissions of the EP-ASU case differs by less than 1% compared to the LP-ASU case. Therefore, the LP-ASU is preferred for a nonintegrated IGCC system, which is a finding consistent with those of other studies (3, 9). Case A. The results of Case A are given in Table 1. Figure 3 shows that the plant efficiency changes with different PNI. The efficiency of LP-ASU case has a maximum at PNI ) 50%. The effiency of EP-ASU case increases monotonically with PNI. The efficiency of EP-ASU is lower than that of LP-ASU until the PNI > 60%. With an increase in PNI, the moisturization decreases. Simultaneously, syngas heating value increases and the coal feed rate decreases. The energy input to the gas turbine is approximately the same. However, the plant efficiency increases with the decrease in coal flow rate. As PNI reaches 51.5% and higher, no moisturization is needed. Furthermore, the air flow to the gas turbine decreases due to the mass flow constraint of turbine inlet nozzle (25). The heating value of saturated syngas decreases slightly and the coal feed rate increases. The efficiency decreases with the increase in the coal flow rate. The LP-ASU-based highest efficiency of 40.42% occurs for Case A4 and is 0.95 percentage points higher than that of the Base Case. For the LP-ASU, the gas turbine power output is nearly constant as PNI varies from 0% to 51.5%. When PNI is larger than 51.5%, the air flow to the gas turbine decreases, which leads to a decrease in compressor power consumption. Thus, the total power output of the gas turbine increases. The steam turbine power output increases due to a decrease in moisturization. Lower moisturization of syngas is associated with less parasitic use of process steam. Therefore, the net energy available for power production by the steam turbine is higher. Case A4 for the LP-ASU has lowest SO2 and CO2 emissions rates on an energy output basis. However, because of the high level of nitrogen injection, Case A7 has the lowest relative NOx emissions. For the EP-ASU, the efficiency is lower than that of the LP-ASU system when PNI is less than 51.5% because the auxiliary power consumption for the EP-ASU is higher than that of the LP-ASU as discussed for the Base Case. Although the EP-ASU-based system has higher oxidant feed power consumption than that of the LP-ASU-based system, the former has much lower nitrogen compressor power consumption. When PNI is above 51.5%, the marginal decrease in nitrogen compressor power consumption for the EP-ASU system versus the LP-ASU system is greater than the marginal increase in the oxidant feed power consumption. Thus, the total auxiliary power consumption of the EP-ASU system is lower, and its efficiency is higher. 1696

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Case 7 based on EP-ASU has the highest efficiency among these cases, which is 1.5 percentage points higher than that of the Base Case with LP-ASU and 0.4 percentage points higher than that of Case 4 with the LP-ASU. Therefore, for IGCC systems with only nitrogen injection, an EP-ASU is preferred in combination with a high level of nitrogen injection. For IGCC based on EP-ASU, the SO2 and CO2 emissions on a plant output basis decrease a little from Case A0 to Case A7. The relative NOx emissions are almost constant when PNI is less than 51.5% and decrease substantially when PNI is above 51.5% due to the increase in efficiency and high level of nitrogen injection. Thus, the case A7 with EP-ASU has the best environmental performance. Case B. The results of Case B are given in Table 2. With an increase in the PAE, the power consumption for the ASU decreases, because less ambient air is compressed by the ASU. The air flow to the compressor increases with increased PAE due to the flow constraint at the turbine inlet nozzle as discussed in Case A. Thus, the power consumption of the compressor increases and the net power output of gas turbine decreases. The marginal decrease in the ASU compressor is lower than the marginal increase in gas turbine compressor power consumption because ASU compressors use intercooling design, which has higher efficiency than the nonintercooled compressor of the gas turbine assumed in this study (9). Thus, the total system power output decreases and the efficiency decreases for both LP-ASU and EP-ASU. Therefore, the plant power output and efficiency decrease with increasing air extraction if there is no nitrogen injection to make up the mass deficit caused by the air extraction. For gas turbines with intercooled compressors, the compressor efficiency may be higher than the air compressor efficiency (26). However, there are additional challenges for startup and operation because of the increased system integration if air extraction is used (20). Emissions of SO2 and CO2 increase a little as PAE increase. The NOx emissions almost keep constant. Case B has higher emissions compared to Case A for both EP-ASU and LPASU. Therefore, air injection only design is not preferred for an IGCC system, regardless of whether the LP or EP-ASU is used. Case C. The results of Case C are given in Table 3. With an increase in PAE, less air is sent to the combustor. The nitrogen injection increases to maintain the mass flow at the turbine inlet nozzle. For LP-ASU, the gas turbine power output is approximately constant and the total auxiliary load increases when PNI is less than 98%. Thus, the total power output and efficiency decreases. When PNI is 98% and the total available nitrogen is used for injection, the mass deficit caused by air extraction cannot be made up by nitrogen injection with a further increase in PAE. Thus, the gas turbine power output decreases. Thus, the total power output and efficiency decrease. For EP-ASU, the gas turbine power output has almost same results as that of LP-ASU. The total auxiliary load decreases with an increase of PAE because the marginal power saving for the ASU air compressor is higher than the increase in the nitrogen compressor work. The power output and the efficiency of the EP-ASU system increase with the increase in PAE until PNI is 98%. With a further increase in air extraction, the mass deficit caused by air extraction cannot be made up by the nitrogen injection. The system efficiency decreases because the gas turbine power output decreases. Case C3 with EP-ASU has the highest efficiency, which is 1.12 percentage points higher than that for the Base Case and 0.17 percentage point higher than that for Case C0 of LP-ASU. Therefore, the optimum air extraction for the IGCC

TABLE 2. Case Study Results for Air Extraction without Nitrogen Injection (Case B) Based on Integrated Gasification Combined Cycle Systems with LP-ASU and EP-ASU

a

description

Base

B1

B2

B3

B4

PAE, % MN2/Mfuel PNI, % moisture fraction in syngas, wt % coal feed rate, kg/s nitrogen feed rate, kg/s saturated syngas heating value, Btu/scf, LHVa air to gas turbine, kg/s combustor exhaust flow rate, 103 gmole/s

0 0 0 28.2 24.2 0 181.4 430.9 14.5

12.5 0 0 28.2 24.3 0 181.4 444.8 14.5

25 0 0 28.2 24.3 0 181.4 458.6 14.4

37.5 0 0 28.2 24.3 0 181.4 471.2 14.4

50 0 0 28.2 24.3 0 181.4 485.1 14.4

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case B: LP-ASU 192.1 132.1 40.0 28.2 284.1 39.47 862 771 1

186.6 132.8 37.6 25.9 281.8 39.11 880 776 1.0

181.0 132.4 35.0 23.6 278.4 38.64 894 785 1.0

175.4 132.1 32.5 21.2 275.0 38.17 903 794 1.0

169.9 131.7 29.9 18.9 271.7 37.69 916 807 1.0

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case B: EP-ASU 192.1 132.2 48.9 36.2 275.4 38.26 898 794 1.0

186.6 132.0 44.8 32.5 273.8 37.98 907 798 1.0

181.0 131.5 40.7 28.7 271.9 37.73 912 803 1.0

175.4 131.2 36.5 24.9 270.1 37.48 921 812 1.1

169.9 130.9 32.4 21.2 268.3 37.22 925 816 1.1

LHV ) lower heating value.

b

HHV ) higher heating value.

based on EP-ASU is between 25% and 37.5%, which is consistent with other studies (2, 11). The EP-ASU is preferred for the combination of nitrogen injection and air extraction. However, the highest overall efficiency is obtained with nitrogen injection only (Case A7 with EP-ASU). Case C3 with an EP-ASU has the lowest emissions of SO2, CO2, and NOx of all the other cases because this case has the highest efficiency. Cost Evaluation. To evaluate whether integration design provides improved economic feasibility, a cost comparison was developed for a nonintegrated design and a preferred integration approach based upon the case study results. For the nonintegrated design, the LP-ASU case was selected since it has higher efficiency than the EP-ASU case. For the integrated design, Case A7 based on EP-ASU was selected since it has the highest efficiency and lowest emissions of all of the case studies. The cost for the nonintegrated IGCC with LP-ASU system is estimated based on a cost model developed by Frey and Akunuri (19). For the integrated IGCC with EPASU design, the available cost information is limited. Thus, an approximate cost is estimated. The details of the cost estimation are given in the SI. The results are listed in Table 4. The direct capital cost for EP-ASU used in the integrated case is higher than that of LP-ASU in the nonintegrated case because of the additional cost of a nitrogen compressor. The steam turbine in the integrated case is larger in size and thus has higher direct cost than that of the nonintegrated case because no moisture injection is used and thus more steam is used in the steam turbine for power production. The direct costs for other process areas are the same for both cases. The total capital requirement (TCR), which includes the capital costs for all process areas, is estimated for the two cases. Although Case A7 has higher direct cost for EP-ASU compared to LP-ASU and higher cost for steam turbine, the TCR is approximately

the same because of higher efficiency and power output for Case A7. However, in reality, the integrated case has no fuel gas saturator since the moisture content in the syngas is zero. Thus, the total capital cost for Case A7 is slightly overestimated because the cost of the saturator is not separable. Therefore, the actual difference in total capital cost between the integrated case and the nonintegrated case may be larger than shown here. At a capacity factor of 0.65, the cost of electricity of the integrated case is 1.1% lower than that of the nonintegrated, and at a capacity factor of 0.85, as shown in Table 4, the difference is -1.3%. Thus, the relative cost advantage of Case A7 improves as capacity factor increases. The absolute difference in the cost of electricity is equivalent to $2.6 million per year for a 500 MW power plant. Since the total capital cost may be overestimated, the actual cost advantage of integrated case may be slightly higher than that implied by these results. IGCC systems are modular. A change in plant size is accomplished by adding more units of each major process area, such as gas turbines, gasifiers, gas cleanup systems, and other major components. Thus, unlike combustionbased power plants, there is much less “economy of scale” associated with increasing plant size (27). Furthermore, the system efficiency is approximately constant with respect to changes in plant size (27). In addition, an advantage of nitrogen injection only over designs that involve air extraction is less complexity for startup and operation of the plant. The former utilizes a nitrogen stream produced anyway by the ASU. The latter requires close coupling between the gas turbine compressor, ASU, and gas turbine combustor, which poses a challenge especially during startup (20). Implications for Decision Making. The results of this study provide answers to the key questions posed in the Introduction and a basis for guidance regarding preferred system integration approaches. VOL. 40, NO. 5, 2006 / ENVIRONMENTAL SCIENCE & TECHNOLOGY

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TABLE 3. Case Study Results for Simultaneous Air Extraction and Nitrogen Injection (Case C) Based on Integrated Gasification Combined Cycle Systems with LP-ASU and EP-ASU description

C0

C1

C2

C3

C4

C5

PAE, % MN2/Mfuel PNI, % moisture fraction in syngas, wt % coal feed rate, kg/s nitrogen feed rate, kg/s saturated syngas heating value, Btu/scf, LHVa air to gas turbine, kg/s combustor exhaust flow rate, 103gmole/s

0 0.60 51.5 0 23.5 36.2 259.1 417.1 14.4

12.5 0.79 67.7 0 23.5 47.6 259.1 417.1 14.4

25 0.98 83.9 0 23.5 59.0 259.1 417.1 14.4

35.9 1.15 98.0 0 23.5 69.0 259.1 417.1 14.4

37.5 1.15 98.0 0 23.5 69.0 259.1 417.1 14.3

50 1.15 98.0 0 23.5 69.0 259.1 417.1 13.9

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW nitrogen compressor, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case C: LP-ASU 192.3 192.4 143.5 142.6 53.4 55.4 27.4 25.1 13.2 17.4 282.4 279.5 40.42 40.00 853 862 753 758 1.0 0.4

192.5 141.6 57.5 22.8 21.5 276.6 39.59 871 767 0.2

192.5 140.8 59.3 20.9 25.1 274.0 39.22 880 776 0.1

191.3 140.8 59.0 20.6 25.1 273.1 39.09 880 776 0.1

181.9 140.5 56.5 18.3 25.1 265.9 38.06 907 798 0.1

gas turbine net power, MW steam turbine net power, MW total auxiliary load, MW oxidant feed, MW nitrogen compressor, MW net plant power output, MW plant efficiency, %, HHVb SO2 emissions, g/MWh CO2 emissions, kg/MWh relative NOx emissions per unit output

Case C: EP-ASU 192.3 192.4 143.6 142.6 54.7 53.0 35.1 31.5 6.7 8.8 281.1 282.0 40.24 40.36 857 853 753 753 1.0 0.4

192.5 141.7 51.3 27.8 10.9 282.8 40.48 853 748 0.2

192.5 140.9 49.8 24.7 12.7 283.6 40.59 848 748 0.1

191.3 140.8 49.3 24.2 12.7 282.8 40.48 853 748 0.1

181.9 140.5 45.3 20.6 12.7 277.1 39.67 871 767 0.1

a

LHV ) lower heating value.

b

HHV ) higher heating value.

TABLE 4. Comparison of Costs for an Integrated Gasification Combined Cycle System of Base Case and an Alternative Design with Nitrogen Injection Onlya description

PAE, % PNI, % moisture fraction in syngas, wt % plant efficiency, %, HHV direct cost, $106 ASU steam turbine total capital requirement, $/kWb fixed operation cost, $/(kW yr) variable operating cost, mills/kWh cost of electricity, mills/kWhc

relative Case A7 Base Case difference, (EP-ASU) (LP-ASU) % 0 98.0 0 40.87

0 0 28.2 39.47

47.5 25.6 1,880 64.7 10.0 44.8

42.2 23.3 1,880 65.7 10.4 45.4

12.6