# IGCC Plant — Bituminous Coal Shell IGCC


# Shell IGCC Plant

Plant Overview
This analysis is based on a 636 MWe (net power output) Integrated Gasi fi cation Combined-Cycle (IGCC) plant using Shell Global Solutions gasi fi cation technology located at a green fi eld site in the midwestern United States. Two pressurized dry-feed entrained fl ow gasi fi cation trains feed two advanced F-Class combustion turbines. Two heat recovery steam generators (HRSGs) and one steam turbine provide additional power. The combination process and heat and mass balance diagram for the Shell IGCC plant is shown in Figure 1. The primary fuel is an Illinois No. 6 bituminous coal with a higher heating value (HHV) of 11,666 Btu/lb. The capacity factor (CF) for the plant is 80 percent without sparing of major train components. A summary of plant performance data for the Shell IGCC plant is presented in Table 1. Table 1. Plant Performance Summary Plant Type Shell IGCC Carbon capture No Net power output (kWe) 635,850 Net plant HHV ef fi ciency (%) 41.1 Primary fuel (type) Illinois No. 6 coal Levelized cost-of-electricity (mills/kWh) @ 80% capacity factor 80.5

Total plant cost ($ x 1,000) $1,256,810

Figure 1. Process Flow Diagram Shell IGCC

Note: Diagram is provided for general reference of major fl ows only. For complete fl ow information, please refer to the fi nal report.

# IGCC Plant — Bituminous Coal Shell IGCC

B_IG_Shell–2 

## Technical Description
The plant uses the Shell gasi fi cation technology. All technology selected in this plant design is assumed to be available to facilitate a 2010 startup date for a newly constructed plant. A summary of performance for the advanced F-Class combustion turbine for the Shell IGCC plant is presented in Table 2. Two gasi fi cation trains process a total of 5,431 tons of coal per day. Dry coal is introduced to the gasi fi er via lockhoppers. Oxygen (O 2 ) is produced in a cryogenic air separation unit. The coal reacts with O 2at about 1,427°C (2,600°F) to produce medium heating value syngas. The syngas is then quenched to around 891°C (1,635°F) by cooled recycled syngas. The syngas passes through a convective cooler and leaves at a temperature near 316°C (600°F). High-pressure saturated steam is generated in the syngas cooler and is joined with the main steam supply. The syngas passes through a cyclone and a raw gas candle fi lter where a majority of the fi ne particles are removed. The ash that is not carried out with the gas forms slag and runs down the interior walls, exiting the gasi fi er in liquid form. The raw syngas then enters a scrubber for removal of chlorides and remaining particulate matter (PM). Following the scrubber, the raw syngas is reheated to 177°C (350°F) and fed to a Carbonyl Sul fi de (COS) hydrolysis reactor where COS is catalytically converted to Hydrogen Sul fi de (H 2 S). The syngas is then cooled to about 35°C (95°F) before passing through a carbon bed to remove ninety fi ve percent of the Hg. The Sul fi nol process then removes essentially all of the CO 2along with the H 2 S and COS. Elemental sulfur is recovered in a Claus bypass-type sulfur recovery unit utilizing O 2instead of air. The Claus plant produces molten sulfur by converting about one-third of the H 2 S in the feed to sulfur dioxide (SO 2 ), then reacting the H 2 S and SO 2to produce sulfur and water. A Brayton cycle fueled with syngas is used in conjunction with a conventional subcritical steam Rankine cycle. Nitrogen dilution (primarily), syngas humidi fi cation (secondarily) and steam injection to a lesser extent aid in minimizing formation of nitrogen oxides (NOx) during combustion in the gas turbine burner section. Two HRSGs and a steam turbine, operating at 12.4 MPa/566oC/566oC (1,800 psig/1,050oF/1,050oF), form the combined-cycle generation component of the plant. The two cycles are integrated by generation of steam in the HRSG, by feedwater heating in the HRSG, and by heat recovery from the IGCC process (convective syngas cooler). The plant produces a net output of 636 MWe. The summary of plant electrical generation performance is presented in Table 3. This con fi guration results in a net plant ef fi ciency of 41.1 percent (HHV basis) or a net plant HHV heat rate of 8,304 Btu/kWh. 

## Environmental Performance
The environmental speci fi cations for a green fi eld IGCC plant are based on the Electric Power Research Institute CoalFleet User Design Basis for Coal-Based IGCC Plants speci fi cation. Low SO 2emissions (less than 4 ppmv in the fl ue gas) are achieved by capture of the sulfur in the Sul fi nol-M AGR process, which removes over 99 percent of the sulfur in the fuel gas. The resulting hydrogen sul fi de-rich regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. Nitrogen oxides emissions are limited by syngas humidi fi cation and nitrogen dilution in the gas turbine combustor to 15 ppmvd (as nitrogen oxides at 15 percent O 2 ). Filterable Table 2. Advanced Gas Turbine Performance 1 Advanced F-Class Net output, MWe 185 Pressure ratio 18.5 Airfl ow, kg/s (lb/s) 431 (950) Firing temperature°C (°F) >1,371 (>2,500)

1 At International Standards Organization conditions fi ring natural gas. Performance information for syngas fi ring is not available.

Table 3. Plant Electrical Generation Electrical Summary Advanced gas turbine x 2, MWe 464.0 HRSG steam turbine, MWe 284.0 Gross power output, MWe 748.0 Auxiliary power requirement, MWe (112.2) Net power output, MWe 635.9

# IGCC Plant — Bituminous Coal Shell IGCC

B_IG_Shell–3 PM discharge to the atmosphere is limited by the use of a cyclone and a barrier fi lter in addition to the syngas scrubber and the gas washing effect of the AGR absorber. Ninety- fi ve percent of the Hg is captured from the syngas by an activated carbon bed. A summary of the resulting air emissions for the Shell IGCC plant is presented in Table 4. 

## Cost Estimation
Plant size, primary/secondary fuel type, construction time, total plant cost (TPC) basis year, plant CF, plant heat rate, fuel cost, plant book life, and plant in-service date were used as inputs to develop capital cost, production cost, and levelized cost-of-electricity (LCOE) estimates. Costs for the plant were based on adjusted vendor-furnished and actual cost data from recent design/build projects. Values for fi nancial assumptions and a cost summary are shown in Table 5. Project contingencies were added to each case to cover project uncertainty and the cost of any additional equipment that could result from detailed design. The project contingencies represent costs that are expected to occur. Project contingency was 13.7 percent of the Shell IGCC case TPC. Process contingency is intended to compensate for uncertainties arising as a result of the state of technology development. Process contingencies represent 2.6 percent of the Shell IGCC case TPC and have been applied to the estimates as follows: Gasi fi ers and Syngas Coolers – 15 percent on all IGCC cases. Mercury Removal – 5 percent on all IGCC cases. Combustion Turbine Generator – 5 percent on all IGCC cases without CCS. Instrumentation and Controls – 5 percent on all IGCC cases. This study assumes that each new plant would be dispatched any time it is available and would be capable of generating maximum capacity when online. Therefore, CF is assumed to equal availability and is 80 percent for IGCC cases. •

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• Table 4. Air Emissions Summary @ 80% Capacity Factor Pollutant Shell IGCC Without

CCS CO 2 • tons/year 3,693,990 • lb/MMBtu 200 • cost of CO 2 avoided ($/ton) N/A SO 2 • tons/year 230 • lb/MMBtu 0.0124 NOx • tons/year 1,082 • lb/MMBtu 0.058 PM ( fi lterable) • tons/year 131 • lb/MMBtu 0.0071 Hg • tons/year 0.011 • lb/TBtu 0.571

# IGCC Plant — Bituminous Coal Shell IGCC

B_IG_Shell–4 Reference: Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. B_IG_Shell_051507 Julianne M. Klara Senior Analyst National Energy Technology Laboratory 626 Cochrans Mill Road P.O. Box 10940 Pittsburgh, PA 15236 412-386-6089 julianne.klara@netl.doe.gov John G. Wimer Systems Analysis Team Lead National Energy Technology Laboratory 3610 Collins Ferry Road P. O. Box 880 Morgantown, WV 26507 304-285-4124 john.wimer@netl.doe.gov 

## Contacts The 636 MWe (net) Shell IGCC plant was projected to have a total capital requirement of $1,977/kWe, resulting in a 20-year LCOE of 80.5 mills/kWh.
Table 5. Major Financial Assumptions and Resulting Cost 1 Major Assumptions

Case: 1x636 MWe net Shell IGCC Plant Size: 635.9 (MWe, net) Heat Rate: 8,304 (Btu/kWh) Primary/Secondary Fuel (type): Illinois #6 Coal Fuel Cost: 1.80 ($/MMBtu) Construction Duration: 3 (years) Plant Life: 30 (years) Total Plant Cost 2 Year: 2007 (January) Plant in Service: 2010 (January) Capacity Factor: 80 (%) Capital Charge Factor: 17.5 (%) Resulting Capital Investment (Levelized 2007 dollars) Mills/kWh Total Plant Cost 49.4 Resulting Operating Costs (Levelized 2007 dollars) 3 Mills/kWh Fixed Operating Cost 5.8 Variable Operating Cost 7.3 Resulting Fuel Cost (Levelized 2007 dollars) @ $1.80 / MMBtu Mills/kWh 18.0 Total Levelized Busbar Cost of Power (2007 dollars) Mills/kWh 80.5

1 Costs shown can vary ± 30%.

2 Total plant cost includes all equipment (complete with initial chemical and catalyst loadings), materials, labor (direct and in direct), engineering and construction management, and contingencies (process and project). Owner’s costs are not included.

3 No credit taken for by-product sales.