IGCC Plant — Bituminous Coal Shell IGCC

Shell IGCC Plant

Plant Overview

This analysis is based on a 636 MWe (net power output) 

Integrated Gasifi cation Combined-Cycle (IGCC) plant using 

Shell Global Solutions gasifi cation technology located at a 

greenfi eld site in the midwestern United States. Two 

pressurized dry-feed entrained fl ow gasifi 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 effi 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 gasifi 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 gasifi cation trains process a total of 5,431 tons of coal 

per day. Dry coal is introduced to the gasifi er via lockhoppers. 

Oxygen (O2

) is produced in a cryogenic air separation unit. 

The coal reacts with O2 at 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 gasifi 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 Sulfi de (COS) 

hydrolysis reactor where COS is catalytically converted to Hydrogen Sulfi de (H2

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 Sulfi nol 

process then removes essentially all of the CO2

 along with the H2S and COS. Elemental sulfur is recovered 

in a Claus bypass-type sulfur recovery unit utilizing O2

 instead of air. The Claus plant produces molten sulfur 

by converting about one-third of the H2S in the feed to sulfur dioxide (SO2), then reacting the H2S and SO2 to 

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 humidifi 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 confi guration results in a net plant effi ciency of 

41.1 percent (HHV basis) or a net plant HHV heat 

rate of 8,304 Btu/kWh.

Environmental Performance

The environmental specifi cations for a greenfi eld IGCC plant are based on the Electric Power Research Institute 

CoalFleet User Design Basis for Coal-Based IGCC Plants specifi cation. Low SO2

 emissions (less than 4 ppmv in the 

fl ue gas) are achieved by capture of the sulfur in the Sulfi nol-M AGR process, which removes over 99 percent 

of the sulfur in the fuel gas. The resulting hydrogen sulfi de-rich regeneration gas from the AGR system is fed to 

a Claus plant, producing elemental sulfur. Nitrogen oxides emissions are limited by syngas humidifi cation and 

nitrogen dilution in the gas turbine combustor to 15 ppmvd (as nitrogen oxides at 15 percent O2). Filterable 

Table 2. Advanced Gas Turbine Performance1

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:

Gasifi 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.

•

•

•

•

Table 4. Air Emissions Summary 

@ 80% Capacity Factor

Pollutant Shell IGCC 

Without 

CCS

CO2

• tons/year 3,693,990

• lb/MMBtu 200

• cost of CO2

 avoided ($/ton) N/A

SO2

• 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 Cost1 

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 Cost2

 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 indirect), engineering and construction management, and contingencies (process and project). Owner’s costs are not included.

3

No credit taken for by-product sales.