Cost and Performance Baseline for 

Fossil Energy Plants

Volume 1b: Bituminous Coal (IGCC) to 

Electricity

Revision 2b – Year Dollar Update

July 31, 2015

DOE/NETL-2015/1727

OFFICE OF FOSSIL ENERGY

National Energy 

Technology Laboratory
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

Disclaimer

This report was prepared as an account of work sponsored by an agency of the United States 

Government. Neither the United States Government nor any agency thereof, nor any of their 

employees, makes any warranty, express or implied, or assumes any legal liability or 

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

product, or process disclosed, or represents that its use would not infringe privately owned rights. 

Reference therein to any specific commercial product, process, or service by trade name, 

trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any agency thereof. The views 

and opinions of authors expressed therein do not necessarily state or reflect those of the United 

States Government or any agency thereof.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

Author List:

National Energy Technology Laboratory (NETL)

Tim Fout

General Engineer

Office of Program Performance & Benefits

Energy Sector Planning and Analysis (ESPA)

Alexander Zoelle, Dale Keairns, Marc Turner, Mark Woods, Norma Kuehn, 

Vasant Shah, Vincent Chou

Booz Allen Hamilton

Lora Pinkerton

WorleyParsons Group, Inc.

This report was prepared by Energy Sector Planning and Analysis (ESPA) for the United States 

Department of Energy (DOE), National Energy Technology Laboratory (NETL). This work was 

completed under DOE NETL Contract Number DE-FE0004001. This work was performed 

under ESPA Task 341.03, Activity 17.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

Acknowledgments

The authors wish to acknowledge the excellent guidance, contributions, and cooperation of the 

NETL staff, particularly:

Tim Fout, NETL Technical Monitor

Kristin Gerdes

Director of OPPB

Travis Shultz

Director, Performance Division of OPPB

John Wimer

Director of OCPR&D

James Black

Daniel Cicero

formerly of NETL

Jared Ciferno

Eric Grol

Jeffrey Hoffmann

Julianne Klara

Patrick Le

Michael Matuszewski

formerly of NETL

Sean Plasynski

Larry Rath

formerly of NETL

Walter Shelton

Gary Stiegel

formerly of NETL

William Summers

Thomas J. Tarka, P.E.

Maria Vargas

John L. Haslbeck

formerly of Booz Allen Hamilton

Eric G. Lewis

formerly of Booz Allen Hamilton

Pamela Capicotto

formerly of Parsons Corporation

Michael Rutkowski

formerly of Parsons Corporation

Ronald Schoff

formerly of Parsons Corporation

Thomas Buchanan

formerly of WorleyParsons Group, Inc.

James Simpson

WorleyParsons Group, Inc.

Elsy Varghese

formerly of WorleyParsons Group, Inc.

Vladimir Vaysman

WorleyParsons Group, Inc.

Richard Weinstein

WorleyParsons Group, Inc.

DOE Contract Number DE-FE0004001
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Table of Contents

Executive Summary.........................................................................................................................1

Results Analysis...............................................................................................................................3

1 Introduction.................................................................................................................................10

2 General Evaluation Basis............................................................................................................13

2.1 Site Characteristics...................................................................................................................13

2.2 Coal Characteristics.................................................................................................................15

2.3 Environmental Targets.............................................................................................................16

2.3.1 Study Cases...........................................................................................................................18

2.3.2 Carbon Dioxide.....................................................................................................................19

2.4 Capacity Factor........................................................................................................................19

2.4.1 Capacity Factor Assumptions...............................................................................................19

2.4.2 Capacity Factor for IGCC Plants..........................................................................................19

2.4.3 Capacity Factor for Plants with Carbon Capture ..................................................................20

2.4.4 Perspective ............................................................................................................................20

2.5 Raw Water Withdrawal and Consumption ..............................................................................20

2.6 Cost Estimating Methodology .................................................................................................21

2.6.1 Capital Costs.........................................................................................................................22

2.6.2 Operation and Maintenance Costs........................................................................................25

2.6.3 CO2 Transport and Storage ...................................................................................................27

2.6.4 Cost of CO2 Captured and Avoided......................................................................................29

2.7 Differences in IGCC Study Cost Estimates Compared to Industry Estimates ........................30

2.7.1 Project Scope ........................................................................................................................30

2.7.2 Labor.....................................................................................................................................31

2.7.3 Contracting Methodology .....................................................................................................31

3 IGCC Power Plants.....................................................................................................................32

3.1 IGCC Common Process Areas.................................................................................................32

3.1.1 Coal Receiving and Storage..................................................................................................32

3.1.2 Air Separation Unit (ASU) Choice and Integration..............................................................33

3.1.3 Water Gas Shift Reactors......................................................................................................37

3.1.4 Mercury Removal .................................................................................................................38

3.1.5 Acid Gas Removal (AGR) Process Selection.......................................................................39

3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection..........................................................42

3.1.7 Slag Handling........................................................................................................................44

3.1.8 Power Island..........................................................................................................................45

3.1.9 Steam Generation Island.......................................................................................................48

3.1.10 Accessory Electric Plant .....................................................................................................51

3.1.11 Waste Treatment/Miscellaneous Systems...........................................................................52

3.1.12 Instrumentation and Control ...............................................................................................52

3.1.13 Performance Summary Metrics ..........................................................................................52

3.2 Shell Global Solutions IGCC Cases ........................................................................................54

3.2.1 Gasifier Background .............................................................................................................54

3.2.2 Process Description...............................................................................................................55

3.2.3 Key System Assumptions.....................................................................................................61

3.2.4 Sparing Philosophy ...............................................................................................................63

3.2.5 Case B1A - Performance Results..........................................................................................64
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3.2.6 Case B1A - Major Equipment List .......................................................................................75

3.2.7 Case B1A - Cost Estimating .................................................................................................80

3.2.8 Case B1B - Shell IGCC Power Plant with CO2 Capture ......................................................86

3.2.9 Case B1B - Performance Results..........................................................................................91

3.2.10 Case B1B - Major Equipment List....................................................................................100

3.2.11 Case B1B - Cost Estimating .............................................................................................105

3.3 CB&I E-GasTM IGCC Cases..................................................................................................111

3.3.1 Gasifier Background ...........................................................................................................111

3.3.2 Process Description.............................................................................................................112

3.3.3 Key System Assumptions...................................................................................................118

3.3.4 Sparing Philosophy .............................................................................................................118

3.3.5 Case B4A - Performance Results........................................................................................119

3.3.6 Case B4A - Major Equipment List .....................................................................................129

3.3.7 Case B4A - Costs Estimating Results.................................................................................134

3.3.8 Case B4B - E-GasTM IGCC Power Plant with CO2 Capture ..............................................140

3.3.9 Case B4B - Performance Results........................................................................................145

3.3.10 Case B4B - Major Equipment List....................................................................................154

3.3.11 Case B4B - Cost Estimating Results.................................................................................159

3.4 General Electric Energy IGCC Cases....................................................................................165

3.4.1 Gasifier Background ...........................................................................................................165

3.4.2 Process Description.............................................................................................................166

3.4.3 Key System Assumptions...................................................................................................173

3.4.4 Sparing Philosophy .............................................................................................................175

3.4.5 Case B5A - Performance Results........................................................................................175

3.4.6 Case B5A - Major Equipment List .....................................................................................186

3.4.7 Case B5A - Cost Estimating ...............................................................................................191

3.4.8 Case B5B - GEE Radiant IGCC with CO2 Capture............................................................197

3.4.9 Case B5B - Performance Results........................................................................................201

3.4.10 Case B5B - Major Equipment List....................................................................................211

3.4.11 Case B5B - Cost Estimating .............................................................................................216

3.4.12 Case B5B-Q - GEE Quench IGCC with CO2 Capture .....................................................222

3.4.13 Case B5B-Q - Performance Results..................................................................................226

3.4.14 Case B5B-Q - Major Equipment List ...............................................................................236

3.4.15 Case B5B-Q - Cost Estimating .........................................................................................241

3.5 IGCC Case Summary.............................................................................................................247

3.5.1 Sensitivities.........................................................................................................................253

4 Revision Control.......................................................................................................................257

5 References.................................................................................................................................261
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibits

Exhibit ES-1 Case configuration summary..................................................................................... 1

Exhibit ES-2 Performance summary and environmental profile for all cases................................ 4

Exhibit ES-3 Net plant efficiency (HHV basis).............................................................................. 5

Exhibit ES-4 Cost summary for all cases ....................................................................................... 6

Exhibit ES-5 COE by cost component............................................................................................ 8

Exhibit 1-1 Case descriptions....................................................................................................... 12

Exhibit 2-1 Site characteristics ..................................................................................................... 13

Exhibit 2-2 Site ambient conditions.............................................................................................. 14

Exhibit 2-3 Design coal ................................................................................................................ 15

Exhibit 2-4 Probability distribution of mercury concentration in the Illinois No. 6 coal............. 16

Exhibit 2-5 MATS and NSPS emission limits for PM, HCl, SO2, NOx, and Hg......................... 16

Exhibit 2-6 Environmental targets................................................................................................ 18

Exhibit 2-7 Capital cost levels and their elements........................................................................ 23

Exhibit 2-8 CO2 transport and storage costs................................................................................. 29

Exhibit 3-1 Air extracted from the combustion turbine and supplied to the ASU in non-carbon 

capture cases ......................................................................................................................... 35

Exhibit 3-2 Typical ASU process schematic ................................................................................ 36

Exhibit 3-3 Flow diagram for a conventional AGR unit .............................................................. 40

Exhibit 3-4 Typical three-stage Claus sulfur plant ....................................................................... 43

Exhibit 3-5 State-of-the-art 2008 F-class combustion turbine performance characteristics using 

natural gas (42) ..................................................................................................................... 45

Exhibit 3-6 Typical fuel specification for state-of-the-art 2008 F-class machines....................... 46

Exhibit 3-7 Allowable gas fuel contaminant level for state-of-the-art 2008 F-class machines.... 47

Exhibit 3-8 Case B1A block flow diagram, Shell IGCC without CO2 capture ............................ 56

Exhibit 3-9 Case B1A stream table, Shell IGCC without capture................................................ 57

Exhibit 3-10 Shell IGCC plant study configuration matrix.......................................................... 62

Exhibit 3-11 Balance of plant assumptions .................................................................................. 63

Exhibit 3-12 Case B1A plant performance summary................................................................... 65

Exhibit 3-13 Case B1A plant power summary ............................................................................. 66

Exhibit 3-14 Case B1A air emissions........................................................................................... 67

Exhibit 3-15 Case B1A carbon balance ........................................................................................ 68

Exhibit 3-16 Case B1A sulfur balance.......................................................................................... 68

Exhibit 3-17 Case B1A water balance .......................................................................................... 69

Exhibit 3-18 Case B1A coal gasification and ASU heat and mass balance schematic ................ 71

Exhibit 3-19 Case B1A syngas cleanup heat and mass balance schematic .................................. 72

Exhibit 3-20 Case B1A combined cycle power generation heat and mass balance schematic .... 73

Exhibit 3-21 Case B1A overall energy balance (0°C [32°F] reference)....................................... 75

Exhibit 3-22 Case B1A total plant cost details............................................................................. 81

Exhibit 3-23 Case B1A owner’s costs.......................................................................................... 84

Exhibit 3-24 Case B1A initial and annual operating and maintenance costs............................... 85

Exhibit 3-25 Case B1A COE breakdown ..................................................................................... 85

Exhibit 3-26 Case B1B block flow diagram, Shell IGCC with CO2 capture ............................... 88

Exhibit 3-27 Case B1B stream table, Shell IGCC with capture ................................................... 89

Exhibit 3-28 Case B1B plant performance summary ................................................................... 91

Exhibit 3-29 Case B1B plant power summary ............................................................................. 92
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-30 Case B1B air emissions........................................................................................... 93

Exhibit 3-31 Case B1B carbon balance ........................................................................................ 94

Exhibit 3-32 Case B1B sulfur balance.......................................................................................... 94

Exhibit 3-33 Case B1B water balance .......................................................................................... 95

Exhibit 3-34 Case B1B coal gasification and ASU heat and mass balance schematic................. 96

Exhibit 3-35 Case B1B syngas cleanup heat and mass balance schematic .................................. 97

Exhibit 3-36 Case B1B combined cycle power generation heat and mass balance schematic..... 98

Exhibit 3-37 Case B1B overall energy balance (0°C [32°F] reference)..................................... 100

Exhibit 3-38 Case B1B total plant cost details ........................................................................... 106

Exhibit 3-39 Case B1B owner’s costs ........................................................................................ 109

Exhibit 3-40 Case B1B initial and annual operating and maintenance costs ............................. 110

Exhibit 3-41 Case B1B COE breakdown.................................................................................... 110

Exhibit 3-42 Case B4A block flow diagram, E-GasTM IGCC without CO2 capture .................. 113

Exhibit 3-43 Case B4A stream table, E-GasTM IGCC without capture ...................................... 114

Exhibit 3-44 E-GasTM IGCC plant study configuration matrix .................................................. 119

Exhibit 3-45 Case B4A plant performance summary................................................................. 120

Exhibit 3-46 Case B4A plant power summary ........................................................................... 121

Exhibit 3-47 Case B4A air emissions......................................................................................... 122

Exhibit 3-48 Case B4A carbon balance ...................................................................................... 123

Exhibit 3-49 Case B4A sulfur balance........................................................................................ 123

Exhibit 3-50 Case B4A water balance ........................................................................................ 124

Exhibit 3-51 Case B4A coal gasification and ASU heat and mass balance schematic .............. 125

Exhibit 3-52 Case B4A syngas cleanup heat and mass balance schematic ................................ 126

Exhibit 3-53 Case B4A combined cycle power generation heat and mass balance schematic .. 127

Exhibit 3-54 Case B4A overall energy balance (0°C [32°F] reference)..................................... 129

Exhibit 3-55 Case B4A total plant cost details........................................................................... 135

Exhibit 3-56 Case B4A owner’s costs........................................................................................ 138

Exhibit 3-57 Case B4A initial and annual operating and maintenance costs............................. 139

Exhibit 3-58 Case B4A COE breakdown ................................................................................... 139

Exhibit 3-59 Case B4B block flow diagram, E-GasTM IGCC with CO2 capture........................ 142

Exhibit 3-60 Case B4B stream table, E-GasTM IGCC with capture............................................ 143

Exhibit 3-61 Case B4B plant performance summary ................................................................. 145

Exhibit 3-62 Case B4B plant power summary ........................................................................... 146

Exhibit 3-63 Case B4B air emissions......................................................................................... 147

Exhibit 3-64 Case B4B carbon balance ...................................................................................... 148

Exhibit 3-65 Case B4B sulfur balance........................................................................................ 148

Exhibit 3-66 Case B4B water balance ........................................................................................ 149

Exhibit 3-67 Case B4B coal gasification and ASU heat and mass balance schematic............... 150

Exhibit 3-68 Case B4B syngas cleanup heat and mass balance schematic ................................ 151

Exhibit 3-69 Case B4B combined cycle power generation heat and mass balance schematic... 152

Exhibit 3-70 Case B4B overall energy balance (0°C [32°F] reference)..................................... 154

Exhibit 3-71 Case B4B total plant cost details ........................................................................... 160

Exhibit 3-72 Case B4B owner’s costs ........................................................................................ 163

Exhibit 3-73 Case B4B initial and annual operating and maintenance costs ............................. 164

Exhibit 3-74 Case B4B COE breakdown.................................................................................... 164

Exhibit 3-75 Case B5A block flow diagram, GEE IGCC without CO2 capture......................... 169
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Exhibit 3-76 Case B5A stream table, GEE IGCC without capture ............................................ 170

Exhibit 3-77 GEE IGCC plant study configuration matrix ........................................................ 174

Exhibit 3-78 Case B5A plant performance summary................................................................. 176

Exhibit 3-79 Case B5A plant power summary ........................................................................... 177

Exhibit 3-80 Case B5A air emissions......................................................................................... 178

Exhibit 3-81 Case B5A carbon balance ...................................................................................... 179

Exhibit 3-82 Case B5A sulfur balance........................................................................................ 179

Exhibit 3-83 Case B5A water balance ........................................................................................ 180

Exhibit 3-84 Case B5A coal gasification and ASU heat and mass balance schematic .............. 182

Exhibit 3-85 Case B5A syngas cleanup heat and mass balance schematic ................................ 183

Exhibit 3-86 Case B5A combined-cycle power generation heat and mass balance schematic .. 184

Exhibit 3-87 Case B5A overall energy balance (0°C [32°F] reference)..................................... 186

Exhibit 3-88 Case B5A total plant cost details........................................................................... 192

Exhibit 3-89 Case B5A owner’s costs........................................................................................ 195

Exhibit 3-90 Case B5A initial and annual operating and maintenance costs............................. 196

Exhibit 3-91 Case B5A COE breakdown ................................................................................... 196

Exhibit 3-92 Case B5B block flow diagram, GEE IGCC with CO2 capture.............................. 198

Exhibit 3-93 Case B5B stream table, GEE IGCC with capture.................................................. 199

Exhibit 3-94 Case B5B plant performance summary ................................................................. 202

Exhibit 3-95 Case B5B plant power summary ........................................................................... 203

Exhibit 3-96 Case B5B air emissions......................................................................................... 204

Exhibit 3-97 Case B5B carbon balance ...................................................................................... 205

Exhibit 3-98 Case B5B sulfur balance........................................................................................ 205

Exhibit 3-99 Case B5B water balance ........................................................................................ 206

Exhibit 3-100 Case B5B coal gasification and ASU heat and mass balance schematic............. 207

Exhibit 3-101 Case B5B syngas cleanup heat and mass balance schematic .............................. 208

Exhibit 3-102 Case B5B combined-cycle power generation heat and mass balance schematic 209

Exhibit 3-103 Case B5B overall energy balance (0°C [32°F] reference)................................... 211

Exhibit 3-104 Case B5B total plant cost details......................................................................... 217

Exhibit 3-105 Case B5B owner’s costs ...................................................................................... 220

Exhibit 3-106 Case B5B initial and annual operating and maintenance costs ........................... 221

Exhibit 3-107 Case B5B COE breakdown.................................................................................. 221

Exhibit 3-108 Case B5B-Q block flow diagram, GEE quench-only IGCC with CO2 capture... 223

Exhibit 3-109 Case B5B-Q stream table, GEE quench-only IGCC with capture ...................... 224

Exhibit 3-110 Case B5B-Q plant performance summary........................................................... 227

Exhibit 3-111 Case B5B-Q plant power summary ..................................................................... 228

Exhibit 3-112 Case B5B-Q air emissions................................................................................... 229

Exhibit 3-113 Case B5B-Q carbon balance ................................................................................ 230

Exhibit 3-114 Case B5B-Q sulfur balance.................................................................................. 230

Exhibit 3-115 Case B5B-Q water balance .................................................................................. 231

Exhibit 3-116 Case B5B-Q coal gasification and ASU heat and mass balance schematic ........ 232

Exhibit 3-117 Case B5B-Q syngas cleanup heat and mass balance schematic .......................... 233

Exhibit 3-118 Case B5B-Q combined cycle power generation heat and mass balance schematic

............................................................................................................................................. 234

Exhibit 3-119 Case B5B-Q overall energy balance.................................................................... 236

Exhibit 3-120 Case B5B-Q total plant cost details..................................................................... 242
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Exhibit 3-121 Case B5B-Q owner’s costs.................................................................................. 245

Exhibit 3-122 Case B5B-Q initial and annual operating and maintenance costs....................... 246

Exhibit 3-123 Case B5B-Q COE breakdown ............................................................................. 246

Exhibit 3-124 Estimated performance and cost results for all cases .......................................... 247

Exhibit 3-125 Plant capital cost for all cases.............................................................................. 249

Exhibit 3-126 COE for all cases ................................................................................................. 250

Exhibit 3-127 Cost of CO2 captured and avoided in all cases.................................................... 251

Exhibit 3-128 Raw water withdrawal and consumption in all cases.......................................... 252

Exhibit 3-129 Capacity factor sensitivity of all cases................................................................. 253

Exhibit 3-130 Sensitivity of COE to coal price for all cases...................................................... 254

Exhibit 3-131 Impact of carbon emissions price on study technologies .................................... 255

Exhibit 3-132 Impact of carbon sales price on study technologies ............................................ 256

Exhibit 4-1 Record of revisions.................................................................................................. 257
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Acronyms and Abbreviations

AACE Association for the Advancement

of Cost Engineering

acfm Actual cubic feet per minute

ACI Activated carbon injection

ADIP Aqueous di-isoproponal 

AEO Annual Energy Outlook

AF Available factor

AGR Acid gas removal

ANSI American National Standards

Institute

Ar Argon

AR As received

Aspen Aspen Plus®

ASU Air separation unit

atm Atmosphere (14.696 psi) 

BACT Best available control technology

BAH Booz Allen Hamilton

BDL Blowdown losses 

BEC Bare erected cost

BFD Block flow diagram

BFW Boiler feedwater

Btu British thermal unit

Btu/hr British thermal units per hour

Btu/kWh British thermal units per kilowatt 

hour

Btu/lb British thermal units per pound

Btu/scf British thermal units per standard 

cubic foot

CAAA Clean Air Act Amendments of 1990

CAIR Clean Air Interstate Rule

CAMR Clean Air Mercury Rule

CB&I Chicago Bridge & Iron Company

CCF Capital charge factor

CCS Carbon capture and sequestration 

CCS Carbon capture and storage

CDR Carbon dioxide recovery

cf Cubic feet

CF Capacity factor

cfm Cubic feet per minute

CFR Code of Federal Regulations

CGE Cold gas efficiency

CGCU Cold gas cleanup

CH4 Methane

CL Closed-loop

cm Centimeter

CO Carbon monoxide

CO2 Carbon dioxide

CO2E Carbon dioxide equivalent

COE Cost of electricity

COH Cost of hydrogen

COR Contracting Officer's Representative

COS Carbonyl sulfide

CRT Cathode ray tube

CS Carbon steel

CT Combustion turbine

CTG Combustion turbine-generator

CWP Circulating water pump

CWR Cooling water return

CWS Circulating water system

CWT Cold water temperature

dB Decibel

DB Dry basis

DCA Direct contact absorber

DCS Distributed control system

DEA Diethanolamine

DI De-ionized

Dia. Diameter

DIPA Diisopropanolamine

DLN Dry low NOx 

DME Di-methyl ether

DOE Department of Energy

DSCR Debt service coverage ratio

DSI Dry sorbent injection

DSRP Direct sulfur recovery process

eGRID Emissions & Generation Resource 

Integrated Database

E-GasTM CB&I gasifier technology

EAF Equivalent availability factor

EGU Electric utility steam generating units

EIA Energy Information Administration

EM Electromagnetic

EMF Emission modification factors

EOR Enhanced oil recovery 

EPA Environmental Protection Agency 

EPC Engineer/Procure/Construct

EPCC Engineering, Procurement and 

Construction Cost

EPRI Electric Power Research Institute

EPCM Engineering/Procurement/ 

Construction Management

ERC Emission reduction credits
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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ESP Electrostatic precipitator

ESPA Energy Sector Planning and Analysis

ETE Effective thermal efficiency

FD Forced draft

FE Fossil energy

FERC Federal Energy Regulatory

Commission

FG Flue gas 

FGD Flue gas desulfurization

FO&M Fixed operations and maintenance

FOAK First-of-a-kind

FRP Fiberglass-reinforced plastic

FSQ Full-slurry quench

ft Foot, Feet

ft, w.g. Feet of water gauge

FW Feedwater

GADS Generating Availability Data System

gal Gallon

gal/MWh Gallons per megawatt hour

GCV Gross calorific value

GDP Gross domestic product

GEE General Electric Energy

GJ Gigajoule

GJ/hr Gigajoules per hour

GHG Greenhouse gas

GHGEV Greenhouse gas emission value

gpd Gallons per day

gpm Gallons per minute

gr/100 scf grains per one hundred standard cubic 

feet

GRI Gas Research Institute

GSU Generator step-up transformers

Gt Gigatonnes

GWh Gigawatt-hour

h, hr Hour

H2 Hydrogen

H2A DOE’s Hydrogen Advisory Group

H2O Water

H2S Hydrogen sulfide

H2SO4 Sulfuric acid

HAP Hazardous air pollutant

HCl Hydrochloric acid

HCPV Hydrocarbon pore volume

HDPE High density polyethylene 

Hg Mercury

HHV Higher heating value

Horiz. Horizontal

hp Horsepower

HP High pressure

HRSG Heat recovery steam generator

HSS Heat stable salts

HV High voltage

HVAC Heating, ventilating, and air 

conditioning

HWT Hot water temperature

Hz Hertz

ICR Information Collection Request

ID Induced draft

IEA International Energy Agency

IEEE Institute of Electrical and Electronics 

Engineers

IGCC Integrated gasification combined 

cycle

IGV Inlet guide vane

in. H2O Inch water

in. Hga Inch mercury (absolute pressure)

in. W.C. Inch water column

IOU Investor-owned utility

IP Intermediate pressure

IPCC Intergovernmental Panel on Climate 

Change

IPM Integrated Planning Model

IPP Independent power producer

IRR Internal rate of return 

IRROE Internal rate of return on equity

ISBL Inside battery limits

ISO International Organization for 

Standardization

kg/GJ Kilograms per gigajoule

kg/hr Kilograms per hour

kg/s Kilograms per second

kgmol Kilogram mole

kgmol/hr Kilogram moles per hour

kJ Kilojoule

kJ/hr Kilojoules per hour

kJ/kg Kilojoules per kilogram

km Kilometer 

KO Knockout

kPa Kilopascal 

kV Kilovolt

kW, kWe Kilowatt electric

kWh Kilowatt-hour

kWt Kilowatt thermal

LAER Lowest Achievable Emission Rate

lb Pound

lb/gal Pound per gallon 
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lb/hr Pounds per hour

lb/ft2 Pounds per square foot

lb/MMBtu Pounds per million British thermal 

units

lbmol Pound mole

lbmol/hr Pound moles per hour

lb/MWh Pounds per megawatt hour

lb/TBtu Pounds per trillion British thermal 

units

LC Life cycle

LCA Life cycle analysis

LCC Life cycle cost

LCI Life cycle inventory

LCIA Life cycle impact assessment

LGTI Louisiana Gasification Technology, 

Inc.

LHV Lower heating value

LIBOR London Interbank Offered Rate

LMP Locational Marginal Price 

LNG Liquified natural gas 

LNB Low NOx burner

LP Low pressure

LPG Liquefied petroleum gas

lpm Liters per minute

LSE Load-serving entities 

LV Low voltage

M Thousand

m Meter

m/min Meters per minute

m3

/min Cubic meters per minute

MAC Main air compressor

MAF Moisture and ash free

MATS Mercury and Air Toxics Standards

Mbbl Thousand barrels

Mcf Thousand cubic feet

MCR Maximum continuous rate

md Millidarcy (a measure of 

permeability)

MDEA Methyldiethanolamine

MeOH Methanol

MHz Megahertz

mi Mile

MJ/Nm3 Megajoules per normal cubic meter

MM Million

MMBtu Million British thermal units 

MMBtu/hr Million British thermal units per hour

MMscf Million standard cubic feet

MMscfd Million standard cubic feet per day

MMscfy Million standard cubic feet per year

mol% Mole percent (percent by mole) 

MNQC Multi Nozzle Quiet Combustor

MPa Megapascal

mpg Miles per gallon

MTG Methanol to gasoline

MVA Mega volt-amps

MW Megawatt

MWe Megawatt electric

MWh Megawatt-hour

MWt Megawatt thermal

N2 Nitrogen

N2O Nitrous oxide

N/A Not applicable

NAAQS National Ambient Air Quality 

Standards

NaOH Sodium hydroxide 

NCF Net capacity factor

Neg. Negligible

NEMA National Electrical Manufacturers 

Association

NEMS National Energy Modeling System

NERC North American Electric Reliability 

Council

NETL National Energy Technology 

Laboratory

NFPA National Fire Protection Association

NG Natural gas

NGCC Natural gas combined cycle

NGL Natural gas liquids

NH3 Ammonia

Nm3 Normal cubic meter

Nm3

/hr Normal cubic meter per hour 

NOAK Nth-of-a-kind

NOx Oxides of nitrogen

NSPS New Source Performance Standards

NSR New Source Review

O2 Oxygen

O&GJ Oil & Gas Journal

O&M Operation and maintenance

OCFn Category n fixed operating cost for 

the initial year of operation

OCVnq Category n variable operating cost for 

the initial year of operation

OD Outside diameter

OEM Original equipment manufacturers

OFA Overfire air

OPPA Office of Program Planning & 

Analysis
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OP/VWO Over pressure/valve wide open

OSHA Occupational Safety and Health 

Administration 

PA Primary air

PAC Powdered activated carbon 

PC Pulverized coal

PAS PAS, Inc.

PC Pulverized coal 

p.f. Power factor

PFD Process flow diagram

PM Particulate matter 

PM10 Particulate matter measuring 10 μm 

(micrometers) or less

PO Purchase order

POTW Publicly owned treatment works

ppbw Parts per billion weight

ppm Parts per million 

ppmv Parts per million volume

ppmvd Parts per million volume, dry 

ppmw Parts per million weight

ppmwd Parts per million weight, dry

PRB Powder River Basin coal region

PSA Pressure swing adsorption

PSD Prevention of significant deterioration

psi Pounds per square inch

psia Pound per square inch absolute

psid Pound per square inch differential

psig Pound per square inch gage

PSFM Power systems financial model

PTFE Teflon (Polytetrafluoroethylene)

PV Present value

QGESS Quality Guidelines for Energy 

System Studies

Qty Quantity

R&D Research and development

RCRA Resource Conservation and Recovery 

Act

RD&D Research, development, and 

demonstration 

RDS Research and Development Solutions, 

LLC

RH Reheater

RSC Radiant syngas cooler

RSP Required selling price

RTO Regional transmission 

operations/operator

SC Supercritical

SC PC Supercritical Pulverized Coal 

scf Standard cubic feet

scfd Standard cubic feet per day

scfh Standard cubic feet per hour

scfm Standard cubic feet per minute

Sch. Schedule

scmh Standard cubic meter per hour

SCOT Shell Claus Off-gas Treating

SCR Selective catalytic reduction process 

or equipment

SDA Spray dryer absorber 

SEAP Office of Strategic Energy Analysis 

& Planning

SFC Synthetic Fuels Corporation

SG Specific gravity

SGC Synthesis gas cooler

SGS Sour gas shift

Shell Shell Global Solutions 

SO2 Sulfur dioxide

SOx Oxides of sulfur

SNCR Selective non-catalytic reduction 

process or equipment

SNG Synthetic natural gas

SRU Sulfur recovery unit

SS Stainless steel

SS Amine SS Specialty Amine 

st Short ton

STG Steam turbine generator

SWS Sour water scrubber

Syngas Synthetic gas

T&D Transmission and distribution

T&S Transport and storage

TASC Total as-spent cost

TCR Total capital requirement

TEWAC Totally Enclosed Water-to-Air 

Cooled

TGTU Tail gas treating unit

tonne Metric ton (1,000 kg)

TOC Total overnight cost

TPC Total plant cost

tpd Ton per day

tph Tons per hour

TPI Total plant investment

U.S. United States

USC Ultra-supercritical

V Volt

VOC Volatile organic compound 

VO&M Variable operations and maintenance

V-L Vapor liquid portion of stream 

(excluding solids)
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

xi

vol% Volume percent

WB Wet bulb

wg Water gauge

WGCU Warm gas cleanup

WGS Water gas shift

wt% Weight percent

yr Year

ZnO Zinc oxide

ZnS Zinc sulfide

$/GJ Dollars per gigajoule

$/kW Dollars per kilowatt

$/MMBtu Dollars per million British thermal 

units

$M Millions of dollars

μS/cm micro Siemens per cm

°C Degrees Celsius

°F Degrees Fahrenheit

5-10s Fifty hour work weeks
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Executive Summary

This report presents the cost and performance results of an assessment of seven integrated 

gasification combined cycle (IGCC) plants. The primary value of this report lies not in the 

absolute accuracy of the capital cost estimates for the individual cases (estimated to be -15

percent/+30), but in the application of a consistent approach to allow meaningful comparisons of 

relative costs among the cases evaluated.

This report is part of an update to Volume 1 of a four-volume series, which consists of:

• Volume 1: Bituminous Coal and Natural Gas to Electricity

• Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks)

• Volume 3: Low Rank Coal and Natural Gas to Electricity

• Volume 4: Bituminous Coal to Liquid Fuels

This report, Volume 1b, retains the IGCC design and performance updates from the November 

2010 release of Volume 1 (Revision 2)1

, but updates the IGCC costs for all cases to 2011 year 

dollars. Volume 1a covers the cost and performance update of all pulverized coal (PC) and 

natural gas combined cycle (NGCC) cases. Section 4 has a revision control table listing the 

updates applied to this report.

Seven power plant configurations were analyzed in this report, including two Shell Global 

Solutions (Shell) gasifiers (with and without carbon dioxide [CO2] capture), two Chicago Bridge 

and Iron (CB&I) E-GasTM full-slurry quench (FSQ) gasifiers (with and without CO2 capture), 

and three General Electric Energy (GEE) gasifiers (one without and two with CO2 capture [one 

radiant and one quench]). A summary of the case configurations in the report is shown in 

Exhibit ES-1.

Exhibit ES-1 Case configuration summary

Case Steam Cycle, 

psig/°F/°F

Combustion 

Turbine

Gasifier 

Technology

H2S 

Separation PM Control CO2SeparationB

B1A 1800/1050/1050 2 x State-of-theart 2008 F-Class Shell Sulfinol-M Cyclone, candle filter, 

and water scrubber N/A

B1B 1800/1000/1000 2 x State-of-theart 2008 F-Class Shell Selexol Cyclone, candle filter, 

and water scrubber

Selexol 2nd

stage

B4A 1800/1050/1050 2 x State-of-theart 2008 F-Class CB&I E-GasTM Refrigerated 

MDEA

Cyclone, candle filter, 

and water scrubber N/A

B4B 1800/1000/1000 2 x State-of-theart 2008 F-Class CB&I E-GasTM Selexol Cyclone, candle filter, 

and water scrubber

Selexol 2nd

stage

B5A 1800/1050/1050 2 x State-of-theart 2008 F-Class GEE Radiant Selexol

Quench, water 

scrubber, and AGR 

adsorber

N/A

B5B 1800/1000/1000 2 x State-of-theart 2008 F-Class GEE Radiant Selexol

Quench, water 

scrubber, and AGR 

adsorber

Selexol 2nd

stage

B5B-Q 1800/1000/1000 2 x State-of-theart 2008 F-Class GEE Quench Selexol

Quench, water 

scrubber, and AGR 

adsorber

Selexol 2nd

stage

 

1 In order to meet the new mercury limits, discussed in Section 2.3, the design of the carbon bed was updated to be a dual sequential carbon bed.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

2

All plant configurations were evaluated based on installation at a greenfield site. Capacity 

factors (CF) are assumed to equal approximate availability at 80 percent for all configurations. 

Achieving such capacity factors would require that these plants be near the top of the dispatch 

list.

The combustion turbines (CT) used in each of the configurations are manufactured in discrete 

sizes; each of the configurations utilizes an identical CT design with the output maximized. 

While the output of the combustion turbines is consistent between configurations, the cases have 

net outputs ranging from 494 (Case B5B-Q) to 629 MW (Case B1A). The range in net output is 

caused by the significant auxiliary load imposed in the CO2 capture cases – primarily due to CO2

compression – and the need for extraction steam for CO2 capture and the sour gas shift (SGS) 

reactions, which reduces steam turbine output. 

Environmental emission requirements are based on the mercury (Hg) and hydrochloric acid 

(HCl) limits set by the March 2013 update to the Utility Mercury and Air Toxics Standards 

(MATS), and particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxide (NOx) limits set 

by the February 2013 update to the New Source Performance Standards (NSPS).

Mercury is controlled with dual sulfur-impregnated carbon beds; H2S is separated with an acid 

gas removal (AGR) process and controlled with a Claus plant to limit SO2 stack emissions; NOx 

formation is minimized with low NOx burners (LNB) and nitrogen dilution; the particulate 

matter is controlled with a syngas scrubber, cyclone, and candle filter; the HCl is primarily 

removed in the syngas scrubber with the remainder removed with the low temperature heat 

recovery condensate, and the combined effluent is treated with calcium hydroxide.

All of the power plant configurations with carbon capture in this report are designed to achieve 

90 percent capture, resulting in atmospheric CO2 emissions at levels far below proposed 

Environmental Protection Agency (EPA) regulation.

2

The performance results presented in this report are unchanged from Revision 2. The 

methodology used in their development included performing steady-state simulations of the 

seven power plant configurations using the Aspen Plus® (Aspen) modeling program. The major 

plant equipment performance and process limits were based on published reports, information 

obtained from vendors and users of the technology, performance data from design/build utility 

projects, and/or best engineering judgment.

In Revision 2, mass and energy balance data from the Aspen models were used to size major 

pieces of equipment, which formed the basis for developing the cost estimates presented in that 

report. The capital and operating costs for the major equipment and plant sub-systems had been 

estimated by WorleyParsons based on the simulation results using an in-house database and 

conceptual estimating models. The cost results were further calibrated using a combination of 

adjusted vendor-furnished data and scaled estimates from previous design/build projects. All 

Revision 2 costs were reported in 2007 dollars.

It was the purpose of this report (Revision 2b) to update the costs to 2011 dollars. This effort 

was accomplished through scaled escalation and corrections. The only exception was to address 

 

2 The Environmental Protection Agency (EPA) proposed a new source performance standard on April 13, 2012, for emissions of carbon dioxide 

for new fossil fuel-fired electric utility generating units. As of the publication of this report, the proposed regulation has been published in the 

Federal Register. (54) The limit set by the proposed regulation is 1,100 lb-CO2/MWh-gross. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

3

the use of a dual carbon system for Hg removal, which was re-costed from a single carbon 

system to address environmental targets discussed in Section 2.3.

The baseline fuel cost for this analysis is specified in the November 2012 revision of the Quality 

Guidelines for Energy System Studies (QGESS) document on “Fuel Prices for Selected 

Feedstocks in NETL Studies.” (1) The first year of capital expenditure price used is $2.78/GJ 

($2.94/MMBtu) for Illinois No. 6 coal delivered to the Midwest, on a higher heating value 

(HHV) basis and in 2011 United States (U.S.) dollars.

The cost metric used in this report is the cost of electricity (COE), which is the revenue that must 

be received by the generator per net megawatt-hour produced to meet the desired internal rate of 

return on equity. The COE is assumed to escalate at a nominal annual rate equal to the general 

inflation rate, i.e., it remains constant or levelized in real terms over the operational period of the 

power plant. The cost of CO2 transport and storage (T&S) of $11 per tonne of CO2 is added to 

the COE and represents a 62 km (100 mile) CO2 pipeline and storage in a deep saline formation 

in the Midwest.3 

The cost and performance of the various fossil fuel-based technologies will be important in 

determining which combination of technologies will be utilized to meet the demands of the 

power market in the future. 

Selection of new generation technologies will depend on many factors, including:

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• COE

• Availability, reliability, and environmental performance

• Current and potential regulations governing air, water, and solid waste discharges from 

fossil-fueled power plants

• Market penetration of clean coal technologies that have matured and improved as a result 

of recent commercial-scale demonstrations under the Department of Energy’s (DOE)

Clean Coal and Carbon Management Program

Results Analysis

Exhibit ES-2 shows the performance and environmental profile summary for all cases. A graph 

of the net plant efficiency (HHV basis) is provided in Exhibit ES-3.

 

3 Estimated using the FE/NETL CO2 Transport Cost Model and the FE/NETL CO2 Saline Storage Cost Model. Additional detail on development 

of these costs is available in the May 2014 revision of the QGESS document “Carbon Dioxide Transport and Storage Costs in NETL Studies.” (26)
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

4

Exhibit ES-2 Performance summary and environmental profile for all cases

Integrated Gasification Combined Cycle

Shell E-GasTM FSQ GEE R+Q

Case Name (Old Case Name)A B1A (5) B1B (6) B4A (3) B4B (4) B5A (1) B5B (2) B5B-Q (2a)

PERFORMANCE

Gross Power Output (MWe) 737 673 738 704 748 734 684

Auxiliary Power Requirement (MWe) 108 177 113 190 126 191 190

Net Power Output (MWe) 629 497 625 513 622 543 494

Coal Flow rate (lb/hr) 436,646 465,264 459,956 484,212 466,898 487,005 486,978

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A N/A N/A N/A

HHV Thermal Input (kWt) 1,492,878 1,590,722 1,572,575 1,655,503 1,596,309 1,665,056 1,664,962

Net Plant HHV Efficiency (%) 42.1% 31.2% 39.7% 31.0% 39.0% 32.6% 29.7%

Net Plant HHV Heat Rate (Btu/kWh) 8,100 10,927 8,585 11,002 8,758 10,459 11,505

Raw Water Withdrawal, gpm 4,150 5,652 4,382 5,757 4,755 5,834 6,137

Process Water Discharge, gpm 788 1,021 905 1,095 984 1,080 1,129

Raw Water Consumption, gpm 3,362 4,631 3,477 4,662 3,771 4,754 5,008

CO2 Capture Rate (%) 0 90 0 90 0 90 90

CO2 Emissions (lb/MMBtu) 197 20 199 20 197 20 20

CO2 Emissions (lb/MWh-gross) 1,361 161 1,448 158 1,434 152 165

CO2 Emissions (lb/MWh-net) 1,595 218 1,711 217 1,724 206 228

SO2 Emissions (lb/MMBtu) 0.004 0.002 0.012 0.002 0.001 0.002 0.002

SO2 Emissions (lb/MWh-gross) 0.029 0.017 0.085 0.017 0.009 0.017 0.018

NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.049

NOx Emissions (lb/MWh-gross) 0.409 0.396 0.434 0.396 0.430 0.376 0.404

PM Emissions (lb/MMBtu) 0.007 0.007 0.007 0.007 0.007 0.007 0.007

PM Emissions (lb/MWh-gross) 0.049 0.057 0.052 0.057 0.052 0.055 0.059

Hg Emissions (lb/TBtu) 0.434 0.372 0.413 0.374 0.412 0.388 0.361

Hg Emissions (lb/MWh-gross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06

A Previous versions of this report used a different naming convention. The old case numbers are provided 

here, paired with the new case numbers for reference.

The primary conclusions that can be drawn are:

• In the non-carbon capture cases the Shell gasifier has the highest net plant efficiency 

(42.1 percent), followed by the two-stage E-GasTM slurry fed gasifier (39.7 percent). 

• The energy penalty associated with adding CO2 capture is due to steam extraction for use 

in the SGS reaction, the auxiliary load for the CO2 separation and compression 

equipment, and a slight derate of the gas turbine due to the higher moisture content of the 

flue gas. The reduction in net plant efficiency ranges from 6 to 11 percentage points with 

the variability being due to the optimum gasifier designs (e.g., slurry vs. dry feed, syngas 

quench vs. syngas heat recovery). The capture and non-capture plant configurations may 

have different optimum gasifier designs. 

• The lowest energy penalty (6 percentage points) corresponds to the GEE Radiant gasifier 

cases primarily due to the non-capture plant design (slurry feed, water quench), which 

results in a high moisture content in the syngas and thus a low addition of shift steam for 

SGS for the capture plant design. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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• The highest energy penalty (11 percentage points) corresponds to the Shell gasifier cases. 

The design uses a dry feed system and, in the non-capture configuration, has relatively 

high heat recovery in the syngas cooler with no water quench, resulting in very low 

moisture content in the syngas. For the capture configuration, a water quench is added,

which increases the moisture content of the syngas for the SGS reaction but decreases the 

heat recovery in the syngas cooler. 

• CB&I E-GasTM has the highest SO2 emissions (0.085 lb/MWh-gross) of the seven cases 

because refrigerated MDEA has the lowest H2S removal efficiency of the AGR 

technologies.

• Emissions of Hg, PM, NOx, HCl, and SO2 are all below the regulatory limits currently in 

effect and applicable to the technologies within this report.

Exhibit ES-3 Net plant efficiency (HHV basis)

Source: NETL

The cost results for all cases are provided in Exhibit ES-4. A graph of the COE is provided in

Exhibit ES-5.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

6

Exhibit ES-4 Cost summary for all cases

Integrated Gasification Combined CycleA

Shell E-GasTM FSQ GEE R+Q

Case Name B1A B1B B4A B4B B5A B5B B5B-Q

COST

Total Plant Cost (2011$/kW) 2,725 3,981 2,372 3,540 2,449 3,387 3,405

Bare Erected Cost 2,067 2,963 1,809 2,638 1,870 2,525 2,548

Home Office Expenses 207 296 181 264 187 253 255

Project Contingency 376 562 322 492 330 467 467

Process Contingency 75 160 61 147 61 143 135

Total Overnight Cost (2011$M) 2,107 2,442 1,830 2,252 1,888 2,279 2,086

Total Overnight Cost (2011$/kW) 3,351 4,917 2,929 4,386 3,036 4,195 4,224

Owner's Costs 626 936 557 846 587 807 819

Total As-Spent Cost (2011$/kW) 3,820 5,605 3,339 5,000 3,461 4,782 4,815

COE ($/MWh) (excluding T&S) 107.0 152.6 99.8 141.9 102.6 135.4 138.7

Capital Costs 59.3 87.0 51.8 77.6 53.7 74.2 74.7

Fixed Costs 14.7 20.5 13.5 19.1 13.7 18.2 18.0

Variable Costs 9.3 13.0 9.2 12.8 9.4 12.2 12.2

Fuel Costs 23.8 32.1 25.2 32.3 25.7 30.7 33.8

COE ($/MWh) (including T&S) 107.0 162.4 99.8 151.8 102.6 144.7 148.9

CO2 T&S Costs 0.0 9.8 0.0 9.9 0.0 9.2 10.2

CO2 Captured Cost (excluding 

T&S), $/tonneB N/A 78.9 N/A 66.5 N/A 63.2 61.0

CO2 Avoided Cost (including 

T&S), $/tonneB N/A 118.7 N/A 102.9 N/A 91.7 99.3

AAll cases use high-risk financial assumptions consistent with NETL’s “QGESS: Cost Estimation 

Methodology for NETL Assessments of Power Plant Performance.” (2)

BBoth the costs of CO2 captured and avoided were calculated based on the non-capture supercritical 

pulverized coal (Case B12A) data provided in the “Cost and Performance Baseline for Fossil Energy 

Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3” report. (3) Case 

B12A has a COE of $82.3/MWh, a CO2 emission rate of 1,618 lb/MWh-gross, a gross plant output of 

579,700 kW, and a net plant output of 550,012 kW.

The primary conclusions that can be drawn are:

• E-GasTM has the lowest total overnight cost (TOC) cost among the non-capture cases. 

The E-GasTM technology has several features that lend it to being lower cost, such as:

o The firetube syngas cooler is much smaller and less expensive than a radiant 

section. E-GasTM can use a firetube boiler because the two-stage design reduces 

the syngas temperature (slurry quench) into a range where a radiant cooler is not 

needed.

o The firetube syngas cooler sits next to the gasifier instead of above or below it, 

which reduces the height of the main gasifier structure. The E-GasTM proprietary 

slag removal system – used instead of lock hoppers below the gasifier – also 

contributes to the lower structure height.

• The normalized TOC of the GEE Radiant gasifier case is approximately 4 percent greater 

than E-GasTM, and Shell is approximately 14 percent higher.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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• The GEE radiant gasifier (GEE quench is less than 1 percent greater than GEE radiant) is 

the low-cost technology in the CO2 capture cases, with E-GasTM normalized TOC 

approximately 5 percent higher and Shell approximately 17 percent higher. 

• The ASU cost represents, on average, 12 percent of the TOC (range from 10-13 percent). 

The ASU cost includes oxygen and nitrogen compression, and in the non-capture cases, it 

also includes the cost of the CT extraction air heat exchanger. With nitrogen dilution 

used to the maximum extent possible, nitrogen compression costs are significant.

• The normalized TOC premium for adding CO2 capture averages 43 percent ($4,430/kW 

versus $3,105/kW).

• The COE is dominated by capital costs and is at least 50 percent of the total in all cases.

• In the non-capture cases the E-GasTM gasifier has the lowest COE, but the differential 

with Shell is reduced (relative to the normalized TOC comparison) primarily because of 

the higher efficiency of the Shell gasifier. The Shell COE is 7 percent higher than EGasTM (compared to 14 percent higher normalized TOC). The GEE gasifier COE is 

about 3 percent higher than E-GasTM.

• In the capture cases the variation in COE is small; however, the order of the GEE and EGasTM gasifiers is reversed. The range is from $144.7/MWh for GEE Radiant to 

$162.4/MWh for Shell with GEE Quench and E-GasTM intermediate at $148.9/MWh and 

$151.8/MWh, respectively. The COE CO2 capture premium for the cases averages 47 

percent (range of 41 to 52 percent).

• The CO2 T&S COE component composes less than 7 percent of the total COE in all 

capture cases.

• In the event that future legislation assigns a cost to carbon emissions, all of the 

technologies examined in this report will become more expensive. The technologies 

without carbon capture will be impacted to a larger extent than those with carbon capture.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

8

Exhibit ES-5 COE by cost component

Source: NETL

Special Considerations on Reported Costs

Capital Costs:

The capital cost estimates documented in this report reflect an uncertainty range of -15

percent/+30 percent, consistent with Association for the Advancement of Cost Engineering 

(AACE) Class 4 cost estimates (i.e., feasibility study) (4) (5) (6), based on the level of 

engineering design performed. In all cases, the report intends to represent the next commercial 

offering and relies on vendor cost estimates for component technologies. It also applies process 

contingencies at the appropriate subsystem levels in an attempt to account for expected but 

undefined costs, which can be a challenge for emerging technologies.

Costs of Emerging Technologies and Designs:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., 

IGCC plants and any plant with CO2 capture) use the same cost estimating methodology as for 

mature plant designs (e.g., PC and NGCC power plants without CO2 capture), which does not 

fully account for the unique cost premiums associated with the initial, complex integrations of 

emerging technologies in a commercial application. Thus, it is anticipated that initial 

deployments of IGCC plants – both with and without CO2 capture – may incur costs higher than 

those reflected within this report. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

9

Other Factors:

Actual reported project costs for all of the plant types are also expected to deviate from the cost 

estimates in this report due to project- and site-specific considerations (e.g., contracting strategy, 

local labor costs, seismic conditions, water quality, financing parameters, local environmental 

concerns, weather delays, etc.) that may make construction more costly. Such variations are not 

captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs 

that are more advanced than those assessed by this report, leading to costs that are lower than 

those estimated herein.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

10

1 Introduction

The objective of this report is to present an accurate, independent assessment of the cost and 

performance of fossil energy power systems, specifically integrated gasification combined cycle 

(IGCC) plants, using a consistent technical and economic approach that reasonably reflects 

current market conditions. 

This report is part of an update to Volume 1 of the four volume series, which consists of:

• Volume 1: Bituminous Coal and Natural Gas to Electricity

• Volume 2: Coal to Synthetic Natural Gas and Ammonia (Various Coal Ranks) 

• Volume 3: Low Rank Coal and Natural Gas to Electricity

• Volume 4: Bituminous Coal to Liquid Fuels

This report, Volume 1b, retains the IGCC design and performance updates from the November 

2010 release of Volume 1 (Revision 2)4, but updates the IGCC costs for all cases to 2011 year 

dollars. Volume 1a covers the cost and performance update of all pulverized coal (PC) and 

natural gas combined cycle (NGCC) cases (3). Section 4 has a revision control table listing the 

updates applied to this report.

Selection of new generation technologies will depend on many factors, including:

• Capital and operating costs

• Overall energy efficiency

• Fuel prices

• Cost of electricity (COE)

• Availability, reliability, and environmental performance

• Current and potential regulation of air, water, and solid waste discharges from fossilfueled power plants

• Market penetration of clean coal technologies that have matured and improved as a result 

of recent commercial-scale demonstrations under the Department of Energy’s (DOE)

Clean Coal and Carbon Management Program

Seven power plant configurations were analyzed, as listed in Exhibit 1-1. The list includes two 

Shell Global Solutions (Shell) gasifiers (with and without carbon dioxide [CO2] capture), two

CB&I E-GasTM full-slurry quench (FSQ) gasifiers (with and without CO2 capture), and three

General Electric Energy (GEE) gasifiers (one without and two with CO2 capture [one radiant and 

one quench]).

While input had previously been sought from various technology vendors during the 

development of the previous revision (Revision 2) of this report, the final assessment of 

performance was determined independently and has not been reviewed by individual vendors. 

 

4 In order to meet the new mercury limits, discussed in Section 2.3, the design of the carbon bed was updated to be a dual sequential carbon bed.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

11

Generating Unit Configurations

A summary of plant configurations considered in this report is presented in Exhibit 1-1. 

Components for each plant configuration are described in more detail in the corresponding report 

sections for each case.

The cases have different gross and net power outputs because of the combustion turbine (CT) 

size constraint. The state-of-the-art 2008 F-class CT used to model the cases comes in a standard 

size of 232 MW when operated on syngas at conditions set by the International Standards 

Organization (ISO). Each case uses two CTs for a combined gross output of 464 MW. In the 

combined cycle a heat recovery steam generator (HRSG) extracts heat from the CT exhaust to 

power a steam turbine. 

The CO2 capture cases consume more extraction steam than the non-capture cases, thus reducing 

the steam turbine output. In addition, the capture cases have a higher auxiliary load requirement 

than non-capture cases, which serves to further reduce net plant output. 

While the two CTs provide 464 MW gross output in all seven cases, the overall combined cycle 

gross output ranges from 673 to 748 MW, which results in a range of net output from 494 (Case 

B5B-Q) to 630 MW (Case B1A). The coal feed rate required to achieve the gross power output 

is also different between the six cases, ranging from 198,220 to 220,899 kg/hr (437,000 to 

487,000 lb/hr).

The balance of this report is organized as follows:

• Chapter 2 provides the basis for technical, environmental, and cost evaluations.

• Chapter 3 describes the IGCC technologies modeled and presents the results for the 

seven cases.

• Chapter 4 includes a record of report revisions.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

12

Exhibit 1-1 Case descriptions

Case

(Old Case NameA)

Unit 

Cycle

Steam Cycle, 

psig/°F/°F

Combustion 

Turbine

Gasifier 

Technology Oxidant H2S Separation

Sulfur 

Removal PM Control NOx Control

CO2

SeparationB

B1A (5) IGCC 1800/1050/1050 2 x State-of-theart 2008 F-Class Shell 95 mol% 

O2

Sulfinol-M Claus 

Plant

Cyclone, candle filter, 

and water scrubber

LNB and 

N2 dilution

B1B (6) IGCC 1800/1000/1000 2 x State-of-theart 2008 F-Class Shell 95 mol% 

O2 Selexol Claus Plant

Cyclone, candle filter, 

and water scrubber

LNB and 

N2 dilution

Selexol 2nd

stage

B4A (3) IGCC 1800/1050/1050 2 x State-of-theart 2008 F-Class CB&I E-GasTM 95 mol% 

O2

Refrigerated 

MDEA

Claus 

Plant

Cyclone, candle filter, 

and water scrubber

LNB and 

N2 dilution

B4B (4) IGCC 1800/1000/1000 2 x State-of-theart 2008 F-Class CB&I E-GasTM 95 mol% 

O2 Selexol Claus Plant

Cyclone, candle filter, 

and water scrubber

LNB and 

N2 dilution

Selexol 2nd

stage

B5A (1) IGCC 1800/1050/1050 2 x State-of-theart 2008 F-Class GEE Radiant 95 mol% 

O2

Selexol Claus 

Plant

Quench, water scrubber, 

and AGR adsorber

LNB and 

N2 dilution

B5B (2) IGCC 1800/1000/1000 2 x State-of-theart 2008 F-Class GEE Radiant 95 mol% 

O2 Selexol Claus Plant

Quench, water scrubber, 

and AGR adsorber

LNB and 

N2 dilution

Selexol 2nd

stage

B5B-Q (2a) IGCC 1800/1000/1000 2 x State-of-theart 2008 F-Class GEE Quench 95 mol% 

O2

Selexol Claus 

Plant

Quench, water scrubber, 

and AGR adsorber

LNB and 

N2 dilution

Selexol 2nd

stage

APrevious versions of this report used a different naming convention. The change was made to provide consistent naming conventions across 

various baseline reports published by NETL. The old case numbers are provided in parenthesis in this table and are paired with the new case 

numbers for reference, and will henceforth be referred to exclusively by their current nomenclature.

BAll cases have a nominal 90 percent removal rate based on the total feedstock minus unburned carbon in slag. The rate of CO2 capture from the

syngas in the Selexol systems varies. An explanation for the difference is provided in Section 2.3.2. All capture cases sequester the CO2 offsite.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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2 General Evaluation Basis

For each of the plant configurations analyzed in this report, an Aspen Plus® (Aspen) model was 

developed and used to generate material and energy balances, which were, in turn, used to 

provide a design basis for items in the major equipment list. The equipment list and material 

balances were used as the basis for generating the capital and operating cost estimates. 

Performance and process limits were based upon published reports, information obtained from 

vendors and users of the technology, performance data from design/build utility projects, and/or 

best engineering judgment. Capital and operating costs were estimated by WorleyParsons based 

on simulation results using an in-house database and conceptual estimating models. Costs were 

further calibrated using a combination of adjusted vendor-furnished data and scaled estimates 

from previous design/build projects. These costs were established in 2007 dollars in prior 

reports and updated to 2011 dollars in this report. No changes were made to the performance or 

base cost methods in this update. Ultimately, a COE was calculated for each of the cases and is 

reported as the revenue requirement figure-of-merit.

The balance of this section discusses the design basis common to all technologies, as well as 

environmental targets and cost assumptions used in this report. Technology specific design 

criteria are covered in subsequent chapters.

2.1 Site Characteristics

All plants in this report are assumed to be located at a generic plant site in Midwestern United 

States (U.S.), with site characteristics and ambient conditions as presented in Exhibit 2-1 and 

Exhibit 2-2. The ambient conditions are the same as ISO conditions.

Exhibit 2-1 Site characteristics

Parameter Value

Location Greenfield, Midwestern U.S.

Topography Level

Size, acres 300

Transportation Rail or Highway

Slag Disposal Off-Site

Water 50% Municipal and 50% Ground Water
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 2-2 Site ambient conditions

Parameter Value

Elevation, (ft) 0

Barometric Pressure, MPa (psia) 0.101 (14.696)

Average Ambient Dry Bulb Temperature, °C (°F) 15 (59)

Average Ambient Wet Bulb Temperature, °C (°F) 10.8 (51.5)

Design Ambient Relative Humidity, % 60

Cooling Water Temperature, °C (°F)A 15.6 (60)

Air composition based on published psychrometric data, mass %

N2 75.055

O2 22.998

Ar 1.280

H2O 0.616

CO2 0.050

Total 100.00

AThe cooling water temperature is the cooling tower cooling water exit temperature. 

This is set to 8.5°F above ambient wet bulb conditions in ISO cases.

The land area assumes that 30 acres are required for the plant proper, and the balance provides a 

buffer of approximately 0.25 mi to the fence line. The extra land could also provide for a rail 

loop if required (rail loop is not included in this report).

In all cases it was assumed that the steam turbine is enclosed in a turbine building. The gasifier 

is not enclosed.

The following design parameters are considered site-specific and are not quantified for this 

report. Allowances for normal conditions and construction are included in the cost estimates.

• Flood plain considerations

• Existing soil/site conditions

• Water discharges and reuse

• Rainfall/snowfall criteria

• Seismic design

• Buildings/enclosures

• Local code height requirements

• Noise regulations – Impact on site and surrounding area

• Other localized environmental concerns

• Weather delays
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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2.2 Coal Characteristics

The design coal is Illinois No. 6 with characteristics presented in Exhibit 2-3. The coal 

properties are from the January 2012 revision of the Quality Guidelines for Energy System 

Studies (QGESS) document “Detailed Coal Specifications.” (7)

Fuel costs used in this report are specified according to the November 2012 QGESS document 

“Fuel Prices for Selected Feedstocks in NETL Studies.” (8) The current coal price is

$2.94/MMBtu (HHV basis) for Illinois No. 6 bituminous coal delivered to the Midwest in June 

2011 dollars.

Exhibit 2-3 Design coal

Rank Bituminous 

Seam Illinois No. 6 (Herrin)

Source Old Ben Mine

Proximate Analysis (weight %)A

As Received Dry

Moisture 11.12 0.00

Ash 9.70 10.91

Volatile Matter 34.99 39.37

Fixed Carbon 44.19 49.72

Total 100.00 100.00

Sulfur 2.51 2.82

HHV, kJ/kg (Btu/lb) 27,113 (11,666) 30,506 (13,126)

LHV, Btu/lb (Btu/lb) 26,151 (11,252) 29,544 (12,712)

Ultimate Analysis (weight %)

As Received Dry

Moisture 11.12 0.00

Carbon 63.75 71.72

Hydrogen 4.50 5.06

Nitrogen 1.25 1.41

Chlorine 0.29 0.33

Sulfur 2.51 2.82

Ash 9.70 10.91

OxygenB 6.88 7.75

Total 100.00 100.00

AThe proximate analysis assumes sulfur as volatile matter

BBy difference

The mercury content of 34 samples of Illinois No. 6 coal has an arithmetic mean value of 

0.09 ppmwd with standard deviation of 0.06 based on coal samples shipped by Illinois mines. (9) 

Hence, as illustrated in Exhibit 2-4, there is a 50 percent probability that the mercury content in 

the Illinois No. 6 coal would not exceed 0.09 ppmwd. The coal mercury content for this report

was assumed to be 0.15 ppmwd for all cases, which corresponds to the mean plus one standard 

deviation and encompasses about 84 percent of the samples. It was further assumed that all of 

the coal Hg enters the gas phase and none leaves with the slag. (10)
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 2-4 Probability distribution of mercury concentration in the Illinois No. 6 coal

Source: NETL

2.3 Environmental Targets

The environmental performance of the IGCC configurations described in this report were 

determined based upon the IGCC performance capabilities at the time of the plant model 

development in prior revisions. Since that time, specific environmental targets have been 

identified that require minimal adjustment to the previously designed systems. The only addition 

was the use of a dual bed carbon system for mercury (Hg) removal. The current environmental 

targets for this study are as follows:

• Mercury (Hg) and hydrochloric acid (HCl) limits were set by the March 2013 update to 

the Utility Mercury and Air Toxics Standards (MATS). (11), (12), (13)

• Particulate matter (PM), sulfur dioxide (SO2), and nitrogen oxide (NOx) limits were set 

by the February 2013 update to the New Source Performance Standards (NSPS). (13),

(14)

The regulations divide the coal types into low rank and non-low rank based on their heating 

value. Coals with a higher heating value (HHV) of greater than 8,300 Btu per pound (Btu/lb) on 

a moist, mineral-matter free basis are considered non-low rank. Therefore, Illinois No. 6 coal, 

with an HHV (moist, mineral-matter free) of 12,900 Btu/lb, is considered a non-low rank coal.

The applicable emission limits imposed by MATS and NSPS are provided in Exhibit 2-5. 

Exhibit 2-5 MATS and NSPS emission limits for PM, HCl, SO2, NOx, and Hg

PollutantA (lb/MWh-gross)

SO2 0.40

NOx 0.70

PM (Filterable) 0.07

Hg 3x10-6

HCl 0.002

ACO emissions may be considered in later revisions of this report, if necessary.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0.00 ppm Hg 0.05 ppm Hg 0.10 ppm Hg 0.15 ppm Hg 0.20 ppm Hg 0.25 ppm Hg 0.30 ppm Hg

Mercury Concentraion in Coal, ppm db

Probability Illinois #6 Sample Will Be At or Below Value

Arithmetic Mean = 0.09 ppm db

Standard Deviation = 0.06 ppm db
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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These new regulations apply to IGCC technologies that begin construction after May 3, 2011. 

Furthermore, these regulations state that (13), (15):

Fossil fuel is defined as natural gas, oil, coal, and any form of solid, liquid, or gaseous 

fuel derived from such material.

Electric utility steam generating units (EGU) are defined as a fossil fuel-fired combustion 

unit of more than 25 megawatts electric (MWe) that serves a generator that produces 

electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and 

supplies more than one-third of its potential electric output capacity and more than 25 

MWe output to any utility power distribution system for sale is considered an electric 

utility steam generating unit.

Fossil fuel-fired means an EGU that is capable of combusting more than 25 MW of fossil 

fuels. To be capable of combusting fossil fuels, an EGU would need to have these fuels 

allowed in its operating permit and have the appropriate fuel handling facilities on-site or 

otherwise available (e.g., coal handling equipment, including coal storage area, belts and

conveyers, pulverizers, etc.; oil storage facilities).

Coal-fired electric utility steam generating units are defined as an EGU and meet the 

definition of “fossil fuel-fired,” which is that it burns coal for more than 10 percent of the 

average annual heat input during any three consecutive calendar years or for more than 

15 percent of the annual heat input during any one calendar year.

Integrated gasification combined cycle electric utility steam generating units, or IGCCs,

are defined as an EGU and meet the definition of “fossil fuel-fired,” which is that it burns 

a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10 percent of 

the average annual heat input during any three consecutive calendar years or for more 

than 15 percent of the annual heat input during any one calendar year in a combinedcycle combustion turbine. No solid coal or solid oil-derived fuel is directly burned in the 

unit during operation.

Unit designed for low-rank virgin coal subcategory is defined as any coal-fired EGU that 

is designed to burn, and that is burning, non-agglomerating virgin coal having a calorific 

value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is 

constructed and operates at or near the mine that produces such coal.

Unit designed for coal ≥8,300 Btu/lb subcategory is defined as any coal-fired EGU that is 

not a coal-fired EGU in the “unit designed for low rank virgin coal” subcategory.

Other regulations that could affect emissions limits from a new plant include the New Source 

Review (NSR) permitting process and Prevention of Significant Deterioration (PSD). The NSR 

process requires installation of emission control technology, meeting either the Best Available 

Control Technology (BACT) determinations for new sources being located in areas meeting 

ambient air quality standards (attainment areas), or Lowest Achievable Emission Rate (LAER) 

technology for sources being located in areas not meeting ambient air quality standards (nonattainment areas). Environmental area designation varies by county and can be established only 

for a specific site location. Based on the Environmental Protection Agency’s (EPA) Green Book 

Non-attainment Area Map, relatively few areas in the Midwestern U.S. are classified as “nonattainment,” so the plant site for this report was assumed to be in an attainment area. (14)
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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In addition to federal regulations, state and local jurisdictions can impose even more stringent 

regulations on a new facility. However, since each new plant has unique environmental 

requirements, it was necessary to apply some judgment in setting the environmental targets for 

this report.

2.3.1 Study Cases

Exhibit 2-6 provides the emissions limits for IGCC plants as well as a brief summary of the 

control technology utilized to satisfy the limits.

Exhibit 2-6 Environmental targets

Pollutant (lb/MWh-gross) Control Technology

SO2 0.40 Selexol, MDEA, or Sulfinol (depending on gasifier 

technology)A

NOx 0.70 Low NOx burners and syngas nitrogen dilution

PM (Filterable) 0.07 Quench, water scrubber, and/or cyclones and candle filters 

(depending on gasifier technology)

Hg 3x10-6 Dual carbon bed

HCl 0.002 Quench, water scrubber, calcium hydroxide treatment, sour 

water stripper

AThe sulfur control technologies are used to remove H2S formed in the gasifier to ultimately limit SO2

emissions after the syngas is combusted in the CT.

Based on published vendor literature, it was assumed that low NOx burners (LNB) and nitrogen 

dilution can achieve 15 ppmvd at 15 percent O2, and that value was used for all cases. (16), (17)

The SO2 limit is met via an acid gas removal (AGR) process. As the emissions limit is based on 

the gross power production of the plant, the actual removal efficiency is dependent on the net 

plant efficiency. Therefore, the required AGR H2S removal efficiency varies from 75 to 98 

percent in the cases without CO2 capture. Vendor data on the AGR processes used in the noncapture cases indicate that the required level of sulfur removal in each technology is possible. 

The sulfur removal efficiency of the CO2 capture cases is approximately 99.9 percent. The high 

rate of H2S removal is a function of the CO2 capture rate requirement (described in Section 2.3.2) 

of the two-stage Selexol process.

Most of the coal ash is removed from the gasifier as slag. The ash that remains entrained in the 

syngas is captured in the downstream equipment, including the syngas scrubber, cyclone, and 

either ceramic or metallic candle filters (E-GasTM and Shell). Each combination of particulate 

control devices can achieve the environmental target.

The Eastman Chemical plant, where syngas from a GEE gasifier is treated, achieved a mercury 

removal efficiency of 95 percent. Sulfur-impregnated activated carbon is used by Eastman as the 

adsorbent in the packed beds operated at 30°C (86°F) and 6.2 MPa (900 psig). Mercury removal 

between 90 and 95 percent has been reported with a bed life of 18 to 24 months. Removal 

efficiencies may be even higher, but, at 95 percent, the measurement precision limit was reached. 

Eastman has yet to experience any mercury contamination in its product. (18) As a mercury 

removal efficiency of up to 97 percent is required to meet the mercury emissions limit, a dual 

sulfur-impregnated carbon bed system (i.e., two beds in series) is required, which is capable of 

achieving greater than 99 percent mercury removal. It was assumed that the mercury removal 
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efficiency is linearly related to bed depth and, therefore, the bed depths were chosen to meet the 

emission limit.

The hydrochloric acid is removed primarily (approximately 95 percent) in the syngas scrubber. 

The remaining chloride in the syngas eventually drops out with condensed water downstream. 

The HCl removed in the syngas scrubber is sent to a treatment plant where calcium hydroxide is 

used to precipitate calcium chloride as a byproduct. The treated stream is mixed with the 

condensed water streams and sent to the sour water stripper, where the HCl is separated out with 

the vapor stream and sent to the Claus plant.

2.3.2 Carbon Dioxide

The EPA proposed a new source performance standard on April 13, 2012 for emissions of 

carbon dioxide for new fossil fuel-fired electric utility generating units. As of the publication of 

this report, the EPA is finalizing a rule that may set CO2 emissions limits below that of fossil 

fuel-fired electric utility generation units without CO2 capture. 

For the cases that have CO2 capture, the basis is a nominal 90 percent carbon removal rate based 

on carbon input from the coal and excluding carbon that exits the gasifier with the slag. In the 

GEE and Shell cases, this was accomplished by using two sour gas shift (SGS) reactors, to 

convert CO to CO2, and a two-stage Selexol process with a second stage CO2 removal efficiency 

of 92 percent, a number that was supported by vendor quotes. All gasifiers, except E-GasTM, 

achieve a nominal carbon removal rate of 90 percent. In the E-GasTM case, in an effort to 

achieve the capture target of 90 percent, a third SGS reactor was added, and the Selexol 

efficiency was increased to 95 percent (the maximum removal efficiency supported by vendor 

quotes). This was done because of the high syngas methane content (1.5 vol% compared to 0.10 

vol% in the GEE radiant gasifier and 0.06 vol% in the Shell gasifier). The E-GasTM capture case 

resulted in 89.9 percent carbon capture.

2.4 Capacity Factor

2.4.1 Capacity Factor Assumptions

Availability is the percent of time during a specific period that a generating unit is capable of 

producing electricity. This report assumes that each new plant would be dispatched any time it is 

available and would be capable of generating the nameplate capacity when online. Therefore, 

the capacity factor (CF) and availability are equal. The operating period selected is also 

important. The calculations assume that the capacity factor and availability are constant over the 

life of the plant, but in actual operation may require that a plant have a higher peak availability to 

counter lower availability in the first several years of operation. 

2.4.2 Capacity Factor for IGCC Plants

The Electric Power Research Institute (EPRI) has reported an availability goal for IGCC plants 

of 85 percent. (19) Plants built before 2000 have achieved availability of 80 percent for limited 

periods of time. Common projections from technology suppliers and EPRI are that IGCC plants 

are capable of 80-85 percent availability without a spare gasifier and could achieve greater than

90 percent availability with a spare gasifier. (20), (21), (22), (23), (24), (25) While an 

availability of 85 percent is the goal, given the IGCC technology experience and the 

commercialization status compared with the more conventional plants (e.g., PC), a CF of 80

percent was selected for IGCC plants with no spare gasifier. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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2.4.3 Capacity Factor for Plants with Carbon Capture

The addition of carbon capture adds extra equipment to the power plant. Preliminary reliability 

analyses show small reductions in reliability if the reliability of the base plant components is 

kept constant. A solvent-based carbon capture technology is used in this report. The capture and 

CO2 compression technologies have commercial operating experience with demonstrated ability 

for high reliability. Given the use of commercial technology, the assumption is made that the 

capacity factors for a given plant with and without carbon capture are the same. Thus, the 

capacity factor for IGCC plants with capture is 80 percent. 

2.4.4 Perspective

Important factors required to achieve the projected IGCC plant availability include a quality 

plant design that utilizes lessons learned from similar plant designs, a focus on life cycle costs, a 

smart predictive maintenance, a trained plant staff, and an economic demand for unit power.

Plant availability is determined by the plant technology, the capital cost invested in the plant 

(e.g., what is the design approach with respect to minimizing scheduled and unplanned 

maintenance), the maintenance requirements, and the customer requirements for the electricity 

(e.g., customer costs due to a unit not being available). Since the unavailability cost will 

decrease with increasing unit availability and the maintenance and capital costs increase with 

increasing unit availability, there will be optimum economic unit availability for a given 

application. This report assumes that the plant design, plant maintenance, and electricity demand 

are consistent with the selected availability.

The existing plant data have not been analyzed with regard to the performance of individual 

plant availability over the life of the plant. As stated, this report assumes a constant availability 

of 80 percent for each year over the life of the plant. It is recognized that the availability of a 

given plant will vary over the life of the plant. As demonstrated by existing plant data, coal 

plants can be designed and operated with yearly availability ranging from 85-100 percent. It is 

assumed that the plants in this report will have yearly availability factors above and below the 

selected value with the effective or levelized availability for the life of the plant being the 

selected value. 

2.5 Raw Water Withdrawal and Consumption

A water balance was performed for each case on the major water consumers in the process. The 

total water demand for each subsystem was determined, and internal recycle water available 

from various sources like boiler feedwater (BFW) blowdown and condensate from syngas (in 

CO2 capture cases) was applied to offset the water demand. The difference between demand and 

recycle is raw water withdrawal. Raw water withdrawal is the water removed from the ground 

or diverted from a municipal source for use in the plant. Raw water consumption is also 

accounted for as the portion of the raw water withdrawn that is evaporated, transpired, 

incorporated into products, or otherwise not returned to the water source from which it was 

withdrawn.

Raw water makeup was assumed to be provided 50 percent by a publicly owned treatment works 

(POTW) and 50 percent from groundwater. Raw water withdrawal is defined as the water 

metered from a raw water source and used in the plant processes for any and all purposes, such 

as cooling tower makeup, BFW makeup, slurry preparation makeup, syngas humidification, and 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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quench system makeup. The difference between withdrawal and process water returned to the 

source is consumption. Consumption represents the net impact of the process on the water 

source.

BFW blowdown and a portion of the sour water stripper blowdown were assumed to be treated 

and recycled to the cooling tower. The cooling tower blowdown and the balance of the SWS 

blowdown streams were assumed to be treated and 90 percent returned to the water source with 

the balance sent to the ash ponds for evaporation.

The largest consumer of raw water in all cases is cooling tower makeup. It was assumed that all 

cases utilized a mechanical draft, evaporative cooling tower, and all process blowdown streams 

were assumed to be treated and recycled to the cooling tower. The design ambient wet bulb 

temperature of 11°C (51.5°F) (Exhibit 2-1 and Exhibit 2-2) was used to achieve a cooling water 

temperature of 16°C (60°F) using an approach of 5°C (8.5°F). The cooling water range was 

assumed to be 11°C (20°F). The cooling tower makeup rate was determined using the following

(26):

• Evaporative losses of 0.8 percent of the circulating water flow rate per 10°F of range

• Drift losses of 0.001 percent of the circulating water flow rate

• Blowdown losses (BDL) were calculated as follows:

BBBBBB = EE

CCCC − 1

Where:

EL – Evaporative Losses

CC – Cycles of concentration

The cycles of concentration are a measure of water quality and a mid-range value of four was 

chosen for this report.

The water balances presented in subsequent sections include the water demand of the major 

water consumers within the process, the amount provided by internal recycle, the amount of raw 

water withdrawal by difference, the amount of process water returned to the source, and the raw 

water consumption, again by difference.

2.6 Cost Estimating Methodology

Detailed information pertaining to topics such as contracting strategy, engineering, procurement, 

and construction (EPC) contractor services, estimation of capital cost contingencies, owner’s 

costs, cost estimate scope, economic assumptions, finance structures, cost of electricity, etc. are 

available in the April 2011 revision of the QGESS document “Cost Estimation Methodology for 

NETL Assessment of Power Plant Performance.” (2) Select portions are repeated in this report 

for completeness.

Capital Costs:

The capital cost estimates documented in this report reflect an uncertainty range of -15

percent/+30 percent, consistent with Association for the Advancement of Cost Engineering 

(AACE) Class 4 cost estimates (i.e., feasibility study) (4) (5) (6), based on the level of 

engineering design performed. In all cases, this report intends to represent the next commercial 

offering and relies on vendor cost estimates for component technologies. It also applies process 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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contingencies at the appropriate subsystem levels in an attempt to account for expected but 

undefined costs, which can be a challenge for emerging technologies.

Costs of Emerging Technologies and Designs:

The cost estimates for plant designs that include technologies that are not yet fully mature (e.g., 

IGCC plants and any plant with CO2 capture) use the same cost estimating methodology as for 

mature plant designs (e.g., PC and NGCC power plants without CO2 capture), which does not 

fully account for the unique cost premiums associated with the initial, complex integrations of 

emerging technologies in a commercial application. Thus, it is anticipated that initial 

deployments of IGCC plants – both with and without CO2 capture – may incur costs higher than 

those reflected within this report. 

Other Factors:

Actual reported project costs for all of the plant types are also expected to deviate from the cost 

estimates in this report due to project- and site-specific considerations (e.g., contracting strategy, 

local labor costs, seismic conditions, water quality, financing parameters, local environmental 

concerns, weather delays, etc.) that may make construction more costly. Such variations are not 

captured by the reported cost uncertainty.

Future Cost Trends:

Continuing research, development, and demonstration (RD&D) is expected to result in designs 

that are more advanced than those assessed by this report, leading to costs that are lower than 

those estimated herein.

2.6.1 Capital Costs

As illustrated in Exhibit 2-7, this report defines capital cost at five levels: BEC, EPCC, TPC, 

TOC, and TASC. BEC, EPCC, TPC, and TOC are “overnight” costs and are expressed in “baseyear” dollars. The base year is the first year of capital expenditure. TASC is expressed in 

mixed, current-year dollars over the entire capital expenditure period, which is assumed in most 

NETL studies to last five years for coal plants.

The Bare Erected Cost (BEC) comprises the cost of process equipment, on-site facilities and 

infrastructure that support the plant (e.g., shops, offices, labs, road), and the direct and indirect 

labor required for its construction and/or installation. The cost of EPC services and 

contingencies are not included in BEC. BEC is an overnight cost expressed in base-year dollars.

The Engineering, Procurement and Construction Cost (EPCC) comprises the BEC plus the cost 

of services provided by the EPC contractor. EPC services include: detailed design, contractor 

permitting (i.e., those permits that individual contractors must obtain to perform their scopes of 

work, as opposed to project permitting, which is not included here), and project/construction 

management costs. EPCC is an overnight cost expressed in base-year dollars.

The Total Plant Cost (TPC) comprises the EPCC plus project and process contingencies. TPC is 

an overnight cost expressed in base-year dollars.

The Total Overnight Cost (TOC) comprises the TPC plus all other overnight costs, including 

owner’s costs. TOC is an “overnight” cost, expressed in base-year dollars and as such does not 

include escalation during construction or interest during construction. 
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The Total As-Spent Cost (TASC) is the sum of all capital expenditures as they are incurred 

during the capital expenditure period including their escalation. TASC also includes interest 

during construction. Accordingly, TASC is expressed in mixed, current-year dollars over the 

capital expenditure period.

Exhibit 2-7 Capital cost levels and their elements

Source: NETL

2.6.1.1 Cost Estimate Basis and Classification

The TPC and Operation and Maintenance (O&M) costs for each of the cases in the report were 

estimated by WorleyParsons using an in-house database and conceptual estimating models. 

Costs were further calibrated using a combination of adjusted vendor-furnished data and scaled 

estimates from previous design/build projects. 

2.6.1.2 System Code-of-Accounts 

The costs are grouped according to a process/system oriented code of accounts. This type of 

code-of-account structure has the advantage of grouping all reasonably allocable components of 

a system or process so they are included in the specific system account. (This would not be the 

case had a facility, area, or commodity account structure been chosen instead). 

2.6.1.3 Estimate Scope 

The estimates represent a complete power plant facility on a generic site. The plant boundary 

limit is defined as the total plant facility within the “fence line” including coal receiving and 

water supply system, but terminating at the high voltage side of the main power transformers. 

CO2 T&S cost is not included in the reported capital cost or O&M costs, but is treated separately 

and added to the COE.

process equipment

supporting facilities

direct and indirect 

labor

BEC

EPCC

TPC

TOC

TASC

EPC contractor services

process contingency

project contingency

pre-production costs

inventory capital

financing costs

other owner’s costs

escalation during capital expenditure period

interest on debt during capital expenditure period

Bare Erected Cost

Engineering, Procurement 

and Construction Cost

Total Plant Cost

Total Overnight Cost

Total As-Spent Cost

BEC, EPCC, TPC and TOC are 

all “overnight” costs 

expressed in base-year dollars.

TASC is expressed in mixedyear current dollars, spread 

over the capital expenditure 

period.
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2.6.1.4 Capital Cost Assumptions

WorleyParsons developed the capital cost estimates for each plant using the company’s in-house 

database and conceptual estimating models for each of the specific technologies. This database 

and the respective models are maintained by WorleyParsons as part of a commercial power plant 

design base of experience for similar equipment in the company’s range of power and process 

projects. A reference bottom-up estimate for each major component provides the basis for the 

estimating models. 

Other key estimate considerations include the following:

• Labor costs are based on Midwest, Merit Shop. The estimating models are based on U.S. 

Gulf Coast and the labor has been factored to Midwest. The basis for the factors is the 

PAS, Inc. (PAS) “Merit Shop Wage & Benefit Survey,” which is published 

annually. Based on the data provided in PAS, WorleyParsons used the weighted average 

payroll plus fringe rate for a standard craft distribution as developed for the estimating 

models. PAS presents information for eight separate regions. For this report, Region 5 

(IL, IN, MI, MN, OH, and WI) was selected.

• The estimates are based on a competitive bidding environment, with adequate skilled 

craft labor available locally.

• Labor is based on a 50-hour work-week (5-10s). No additional incentives such as perdiem allowances or bonuses have been included to attract craft labor. 

• While not included at this time, labor incentives may ultimately be required to attract and 

retain skilled labor depending on the amount of competing work in the region, and the 

availability of skilled craft in the area at the time the projects proceed to construction.

• The estimates are based on a greenfield site. 

• The site is considered to be Seismic Zone 1, relatively level, and free from hazardous 

materials, archeological artifacts, or excessive rock. Soil conditions are considered 

adequate for spread footing foundations. The soil bearing capability is assumed adequate 

such that piling is not needed to support the foundation loads. 

• Engineering and Construction Management are estimated at 8-10 percent of BEC. These 

costs consist of all home office engineering and procurement services as well as field 

construction management costs. Site staffing generally includes a construction manager, 

resident engineer, scheduler, and personnel for project controls, document control, 

materials management, site safety, and field inspection.

2.6.1.5 Price Fluctuations

During the course of this report, the prices of equipment and bulk materials fluctuated 

substantially. Some reference quotes pre-dated the 2011 year cost basis while others were 

received post-2011. All vendor quotes used to develop these estimates were adjusted to June 

2011 dollars accounting for the price fluctuations. Price indices, e.g., The Chemical Engineering 

Plant Cost Index (27) and the Gross Domestic Product Chain-type Price Index (28), were used as 

needed for these adjustments. 

2.6.1.6 Cross-comparisons 

In all technology comparison studies, the relative differences in costs are often more significant 

than the absolute level of TPC. This requires cross-account comparison between technologies to 

review the consistency of the direction of the costs. 
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In performing such a comparison, it is important to reference the technical parameters for each 

specific item, as these are the basis for establishing the costs. Scope or assumption differences 

can quickly explain any apparent anomalies. There are a number of cases where differences in 

design philosophy occur. Some key examples are: 

• The CT account in the GEE cases includes a syngas expander, which is not required for 

the E-GasTM or Shell cases.

• The CTs for the capture cases include an additional cost for firing a high hydrogen

content fuel.

• The Shell gasifier syngas cooling configuration is different between the CO2-capture and 

non-CO2-capture cases, resulting in a significant differential in thermal duty between the 

syngas coolers for the two cases. 

2.6.1.6.1 Process Contingency

Process contingencies were applied to the estimates in this report as follows:

• Slurry Prep and Feed – 5 percent on GEE cases - systems are operating at 

approximately 800 psia as compared to 600 psia for the other cases

• Gasifiers and Syngas Coolers – 15 percent on all cases - next-generation commercial 

offering and integration with the power island

• Two-Stage Selexol – 20 percent on all capture cases - unproven technology at 

commercial scale in IGCC service

• Mercury Removal – 5 percent on all cases - minimal commercial scale experience in 

IGCC applications

• CTG – 5 percent on all non-capture cases - syngas firing and ASU integration; 10

percent on all capture cases – high hydrogen firing. 

• Instrumentation and Controls – 5 percent on all accounts– integration issues

2.6.1.7 Owner’s Costs

Two examples of what could be included in the “other” owner’s costs are rail spur and switch 

yard costs.

Switch yard costs are dependent on voltage, configuration, number of breakers, layout, and airinsulated vs. gas-insulated. As a rule of thumb, a 345 kV switchyard (air-insulated, ring bus) 

would cost roughly $850,000 per breaker.

On-site only rails (excludes long runs) would be expected to cost in the range of $850,000 to 

$950,000 per mile (relatively flat level terrain) plus the costs of any switches/turnouts 

(approximately $50,000 each) and road crossings (approximately $300 per linear foot).

Additional details and explanation of owner’s costs are available in the April 2011 revision of 

the QGESS document “Cost Estimation Methodology for NETL Assessment of Power Plant 

Performance.” (2)

2.6.2 Operation and Maintenance Costs

The production costs or operating costs and related maintenance expenses (O&M) pertain to 

those charges associated with operating and maintaining the power plants over their expected 

life. These costs include: 
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• Operating labor

• Maintenance – material and labor

• Administrative and support labor

• Consumables

• Fuel

• Waste disposal

• Co-product or by-product credit (that is, a negative cost for any by-products sold)

There are two components of O&M costs; fixed O&M, which is independent of power 

generation, and variable O&M, which is proportional to power generation. Taxes and insurance 

are included as fixed O&M costs, totaling 2 percent of the TPC.

2.6.2.1 Operating Labor

Operating labor cost was determined based on of the number of operators required for each

specific case. The average base labor rate used to determine annual cost is $39.70/hour. The 

associated labor burden is estimated at 30 percent of the base labor rate.

2.6.2.2 Maintenance Material and Labor

Maintenance cost was evaluated on the basis of relationships of maintenance cost to initial 

capital cost. This represents a weighted analysis in which the individual cost relationships were 

considered for each major plant component or section.

2.6.2.3 Administrative and Support Labor

Labor administration and overhead charges are assessed at a rate of 25 percent of the burdened 

O&M labor.

2.6.2.4 Consumables

The cost of consumables, including fuel, was determined on the basis of individual rates of 

consumption, the unit cost of each specific consumable commodity, and the plant annual 

operating hours. 

Quantities for major consumables such as fuel and sorbent were taken from technology-specific 

heat and mass balance diagrams developed for each plant application. Other consumables were 

evaluated on the basis of the quantity required using reference data. 

The quantities for initial fills and daily consumables were calculated on a 100 percent operating 

capacity basis. The annual cost for the daily consumables was then adjusted to incorporate the 

annual plant operating basis, or CF. 

Initial fills of the consumables, fuels and chemicals, are different from the initial chemical 

loadings, which are included with the equipment pricing in the capital cost.

2.6.2.5 Waste Disposal

Waste quantities and disposal costs were determined/evaluated similarly to the consumables. In 

this report slag is considered a waste with a disposal cost of $27.80/tonne ($25.11/ton). The 

carbon used for mercury control is considered a hazardous waste with disposal cost of 

$1,433/tonne ($1,300/ton).
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2.6.2.6 Co-Products and By-Products 

By-product quantities were also determined similarly to the consumables. However, due to the 

variable marketability of these by-products, specifically sulfur, no credit was taken for its

potential salable value.

It should be noted that by-product credits and/or disposal costs could potentially be an additional 

determining factor in the choice of technology for some companies and in selecting some sites. 

A high local value of the product can establish whether or not added capital should be included 

in the plant costs to produce a particular co-product. Slag is a potential by-product in certain 

markets. As stated above, the slag is considered a waste in this report with a concomitant 

disposal cost.

2.6.3 CO2 Transport and Storage

The cost of CO2 transport and storage (T&S) in a deep saline formation is estimated using the 

FE/NETL CO2 Transport Cost Model and the FE/NETL CO2 Saline Storage Cost Model. 

Additional detail on development of these costs is available in the May 2014 revision of the 

QGESS document “Carbon Dioxide Transport and Storage Costs in NETL Studies.” (29)

T&S costs are reported as first-year costs in $/tonne of CO2, increasing at a nominal rate of 3 

percent per year, consistent with the general inflation rate assumed in NETL’s energy systems 

studies. From the perspective of the CO2 source (e.g., a power plant or other energy conversion 

facility), these costs are treated as a disposal cost for each tonne of CO2 captured during the 

assumed 30-year operational period. From the pipeline and storage site’s perspective, this cost 

represents the minimum price that the operators must charge so that they receive the revenue 

needed across the 30-year operational period to cover all costs and provide the required internal 

rate of return on equity (IRROE). All costs are reported in 2011 dollars.

The Transport Cost Model provides cost estimates for the construction and operation of a 

dedicated pipeline for transporting CO2 from a CO2 source to a CO2 storage site. The pipeline is 

assumed to be buried in the shallow subsurface and the CO2 along the pipeline is assumed to be 

at the temperature of the surrounding soil, typically about 50 o

F. The CO2 entering the pipeline 

at the plant gate is assumed to be at a pressure of 2,200 psig and exiting the pipeline at the 

storage site at a pressure of 1,200 psig. At these pressures, CO2 is a liquid at temperatures from 

approximately -64°F to 88°F.

It is further assumed that the pipeline is 100 km long (62.1 mi) and transports 3.2 million tonnes 

of CO2 each year on average or approximately 8,770 tonnes per day on average. The pipeline is 

designed to operate at 80 percent of its maximum mass flow capacity, so the design maximum 

daily mass flow rate of CO2 is about 10,960 tonnes/day. The model determines the smallest 

standard diameter pipe that can transport this mass flow of CO2 the required distance without 

boosting the pressure. The model also determines the smallest standard diameter pipe that can 

transport this mass flow of CO2 the required distance assuming boost pumps are placed at equal 

intervals along the pipeline to boost the pressure from 1,200 psig to 2,200 psig. The model then 

determines which of these configurations (e.g., no boost pumps, one boost pump, two boost 

pumps, three boost pumps, etc.) is least expensive. The capital and operating costs used in the 

model were taken from the open literature. The capital costs for the pipeline are based on capital 

costs for natural gas pipelines reported in the Oil and Gas Journal with adjustments for the higher 

pressures used in CO2 pipelines.
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The financial parameters used in the FE/NETL CO2 Transport Cost Model are:

• Debt to equity ratio: 50%/50%

• Nominal interest rate on debt: 4.5%/year

• Nominal IRROE: 12%

• Escalation rate: 3%

• Tax rate: 38%

• Project contingency factor of 15%

The FE/NETL CO2 Transport Cost Model determines the first-year break-even price that needs 

to be charged to transport the CO2 in order to cover all costs including the minimum return on 

equity. The model uses a weighted average cost of capital methodology in determining the 

break-even first-year CO2 price. From the perspective of the CO2 source, the break-even price is 

also the minimum cost of transporting CO2. Transport costs are estimated to be $2.24/tonne in 

2011 dollars.

Storage costs are based on the FE/NETL CO2 Saline Storage Cost Model. This model provides 

detailed cost estimates for the injection and monitoring of CO2 under EPA regulations for Class 

VI injection wells as well as monitoring and reporting requirements under Subpart RR of the 

Greenhouse Gas Reporting Rule. 

Inputs to the FE/NETL CO2 Saline Storage Cost Model that have a significant influence on cost 

include financial parameters, timelines for the various stages of storage, and important activities 

occurring in each stage. The financial parameters include:

• Debt to equity ratio: 45%/55%

• Nominal interest rate on debt: 5.5%/year

• Nominal IRROE: 12%

• Escalation rate: 3%

• Financial responsibility requirements for post-injection site care and site closure are met 

by pre-funding a modified trust fund over the period of injection operations

• Project contingency factor of 15% and process contingency factor of 20%

In the FE/NETL CO2 Saline Storage Cost Model, the sequestration process is divided into six 

stages. The timelines and important activities impacting costs for these stages are as follows:

• Regional evaluation and initial site selection: 1 year

• Site characterization: 3 years; four sites undergo site characterization with one successful 

site selected; pore space rights are leased

• Permitting: 2 years; drill, test, and complete injection wells

• Operations: 30 years; installation of buildings, surface equipment, monitoring wells and 

other monitoring equipment; comply with permit requirements; fund modified trust fund 

to cover financial responsibility requirements for post-injection site care and site closure

• Post-injection site care and site closure: 50 years; continue monitoring, verification and 

accounting (mega volt-amps [MVA]) per permit; costs are covered by storage site 

operator’s trust fund

• Long-term stewardship: This stage is not explicitly included in the model; however, the 

possible financial implication of long-term stewardship is included in the model as a 

state-sponsored trust fund that the storage operator pays into during operations
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Due to the variances in the geologic formations that make up saline formations across the U.S., 

region-specific storage and monitoring costs are developed to correspond to the plant locations 

used in NETL techno-economic studies of energy conversion facilities. Results from the 

FE/NETL CO2 Saline Storage Cost Model for storage and monitoring costs were aligned with 

the NETL studies by taking four generic plant locations and overlaying them with possible 

sequestration basins from the cost model resulting in the following pairings:

• Midwest plant location – Illinois Basin

• Texas plant location – East Texas Basin

• North Dakota plant location – Williston Basin

• Montana plant location – Powder River Basin

CO2 storage supply-cost curves were developed for each of the 4 basins of interest with the 

resulting cost for each basin at 25 gigatonnes (Gt) of potential storage shown in Exhibit 2-8. 

Choosing this point on the supply-cost curves provides a conservative estimate of the storage 

cost since many decades, if not more than a century, will pass before 25 Gt of CO2 is stored in 

any of the 4 individual basins. For example, 25 Gt of storage would be sufficient for 125 GW of 

coal power with 90 percent CO2 capture operating over 30 years. 

The far right column of Exhibit 2-8 shows the total T&S costs used in NETL system studies for 

each plant location rounded to the nearest whole dollar. Only the $11/tonne value is used in this 

volume of the baseline study report since all cases are located in the Midwest.

Exhibit 2-8 CO2 transport and storage costs

Plant 

Location Basin Transport

(2011 $/tonne)

Storage Cost at 25 Gt

(2011 $/tonne)

T&S Value for System 

StudiesA (2011$/tonne)

Midwest Illinois

2.24

8.69 11

Texas East Texas 8.83 11

North Dakota Williston 13.95 16

Montana Powder River 21.81 24

AThe sum of transport and storage costs is rounded to the nearest dollar

2.6.4 Cost of CO2 Captured and Avoided

The cost of captured CO2 represents the minimum CO2 plant gate sales price that will incentivize 

carbon capture in lieu of a defined reference non-capture plant. The cost of captured CO2 is 

calculated using the following formula:

CCCCCCCC oo CCCC2 CCCCCCCCCCCCCCCC = (CCCC CCCCCC − CCCC NNNNNN CCCCCC)

CCCC2 CCCCCCCCCCCCCCCC

The cost of CO2 avoided represents the minimum CO2 emissions price, when applied to both the 

capture and non-capture plant that will incentivize carbon capture in lieu of a defined reference 

non-capture plant. The cost of CO2 avoided is calculated using the following formula:

CCCCCCCC oo CCCC2 AAAA AA = (CCCC CCCCCC wwwwwwh TT& − CCCC NNNNNN CCCCCC)

CCCC2 EEEE EE NNNNNN CCCCCC − CCCC2 EEEE EE CCCCCC
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where:

• CCS – the capture plant for which the cost of CO2 captured/avoided is being calculated

• Non-CCS – the reference non-capture plant, as described below

• COE – the cost of electricity, reported in $/MWh

o The CCS plant includes compression to 2,215 psia

o For CO2 Captured, the COE excludes T&S costs

o For CO2 Avoided, the COE includes T&S costs

• CO2 Captured – the rate of CO2 captured, reported in tonne/MWh

• CO2 Emissions – the rate of CO2 emitted out the stack, reported in tonne/MWh

For today’s greenfield coal with CCS plants, the reference non-capture plant used to calculate the 

cost of captured and avoided CO2 is a supercritical pulverized coal (SCPC) plant without 

capture. 

2.7 Differences in IGCC Study Cost Estimates Compared to Industry 

Estimates

2.7.1 Project Scope

For this report, the scope of work is generally limited to work inside the project “fence line.” For 

outgoing power, the scope stops at the high voltage side of the main power transformers. 

Some typical examples of items outside the fenceline include:

• New access roads and railroad tracks

• Upgrades to existing roads to accommodate increased traffic

• Makeup water pipe outside the fence line

• Landfill for on-site waste (slag) disposal

• Electrical transmission lines & substation

Estimates in this report are based on a generic mid-western greenfield site having “normal” 

characteristics. Accordingly, the estimates do not address items such as:

• Piles or caissons

• Rock removal

• Excessive dewatering

• Expansive soil considerations

• Excessive seismic considerations

• Extreme temperature considerations

• Hazardous or contaminated soils

• Demolition or relocation of existing structures

• Leasing of offsite land for parking or laydown

• Busing of craft labor to site

• Costs of offsite storage

This report is based on a reasonably “standard” plant. Some unusual or extraordinary process 

equipment that is not included in the analysis are as follows:

• Excessive water treatment equipment
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• Air-cooled condenser

• Automated coal reclaim

• Zero liquid discharge equipment

• SCR catalyst 

This report is based on plant equipment sized for non-capture only; none of the equipment has 

been sized to accommodate a future conversion to CO2 capture. 

2.7.2 Labor

This report is based on Merit Shop (non-union) labor. If a project is to use union labor, there is a 

strong likelihood that overall labor costs will be greater than those estimated in this report. 

This report is based on a 50 hour work week, with an adequate local supply of skilled craft labor. 

No additional incentives such as per-diem allowances or bonuses have been included to attract 

and retain skilled craft labor.

2.7.3 Contracting Methodology

The estimates in this report are based on a competitively bid, multiple subcontract approach, 

often referred to as Engineering/Procurement/Construction Management (EPCM). Accordingly, 

the estimates do not include premiums associated with an EPC approach. It is believed that, 

given current market conditions, the premium charged by an EPC contractor could be as much as 

30 percent or more over an EPCM approach.
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3 IGCC Power Plants

Seven IGCC power plant configurations were evaluated, and the results are presented in this 

section. Each design is based on a market-ready technology that is assumed to be commercially 

available to support startup.

The seven cases are based on the GEE gasifier, the CB&I E-GasTM gasifier, and the Shell 

gasifier, each with and without CO2 capture. As discussed in Section 1, the net output for the 

seven cases varies because of the constraint imposed by the fixed CT output and the high 

auxiliary loads imparted by the CO2 capture process.

The CT is based on a state-of-the-art 2008 F-class design. The HRSG/steam turbine cycle varies

based on the CT exhaust conditions. Steam conditions are nominally 12.4 MPa/560°C/560°C 

(1800 psig/1040°F/1040°F) for all of the non-CO2 capture cases and 12.4 MPa/534°C/534°C 

(1800 psig/994°F/994°F) for all of the CO2 capture cases. The capture cases have a lower main 

and reheat steam temperature primarily because the turbine firing temperature is reduced to 

allow for a parts life equivalent to NGCC operation with a high-hydrogen content fuel, which 

results in a lower turbine exhaust temperature. 

The evaluation scope included developing heat and mass balances and estimating plant 

performance. Equipment lists were developed for each design to support plant capital and 

operating cost estimates. The evaluation basis details, including site ambient conditions, fuel 

composition, and environmental targets are provided in Section 2. Section 3.1 covers general 

information that is common to all of the cases; case-specific information is subsequently 

presented in Sections 3.2, 3.3, and 3.4.

3.1 IGCC Common Process Areas

The cases have process areas, which are common to each plant configuration such as coal 

receiving and storage, oxygen supply, gas cleanup, power generation, etc. As detailed 

descriptions of these process areas for each case would be burdensome and repetitious, they are 

presented in this section for general background information. Where there is case-specific 

performance information, the performance features are presented in the relevant case sections.

3.1.1 Coal Receiving and Storage

The function of the coal receiving and storage system is to unload, convey, prepare, and store the 

coal delivered to the plant. The scope of the system is from the trestle bottom dumper and coal 

receiving hoppers up to and including the slide gate valves at the outlet of the coal storage silos. 

Coal receiving and storage is identical in design for all seven cases; however, coal preparation 

and feed are gasifier-specific.

Operation Description – The coal is delivered to the site by 100-car unit trains comprised of 91 

tonne (100 ton) rail cars. The unloading is done by a trestle bottom dumper, which unloads the 

coal into two receiving hoppers. Coal from each hopper is fed directly into a vibratory feeder. 

The 8 cm x 0 (3" x 0) coal from the feeder is discharged onto a belt conveyor. Two conveyors 

with an intermediate transfer tower are assumed to convey the coal to the coal stacker, which 

transfer the coal to either the long-term storage pile or to the reclaim area. The conveyor passes 

under a magnetic plate separator to remove tramp iron and then to the reclaim pile.
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The reclaimer loads the coal into two vibratory feeders located in the reclaim hopper under the 

pile. The feeders transfer the coal onto a belt conveyor that transfers the coal to the coal surge 

bin located in the crusher tower. The coal is reduced in size to 3 cm x 0 (11⁄4" x 0) by the 

crusher. A conveyor then transfers the coal to a transfer tower. In the transfer tower the coal is 

routed to the tripper, which loads the coal into one of three silos. Two sampling systems are 

supplied: the as-received sampling system and the as-fired sampling system. Data from the 

analyses are used to support the reliable and efficient operation of the plant.

3.1.2 Air Separation Unit (ASU) Choice and Integration

In order to economically and efficiently support IGCC projects, air separation equipment has 

been modified and improved in response to production requirements and the consistent need to 

increase single train output. “Elevated pressure” air separation designs have been implemented 

that result in distillation column operating pressures that are about twice as high as traditional 

plants. In this report, the main air compressor discharge pressure was set at 1.3 MPa (190 psia) 

compared to a traditional ASU plant operating pressure of about 0.7 MPa (105 psia). (30) For 

IGCC designs the elevated pressure ASU process minimizes power consumption and decreases 

the size of some of the equipment items. When the air supply to the ASU is integrated with the 

CT, the ASU operates at or near the supply pressure from the CT’s air compressor.

The power requirement for the ASU used in this report is 0.039 kW/lb-O2 product for all cases 

and the total power requirement, including the oxygen and nitrogen compressors, ranges from 

0.064 kW/lb-O2 product in the E-GasTM CO2 capture case (B4B) to 0.072 kW/lb-O2 product in 

the Shell non-capture case (B1A).

3.1.2.1 Residual Nitrogen Injection

The residual nitrogen that is available after gasifier oxygen and nitrogen requirements have been 

met is often compressed and sent to the CT. Since all product streams are being compressed, the 

ASU air feed pressure is optimized to reduce the total power consumption and to provide a good 

match with available compressor frame sizes.

Increasing the diluent flow to the CT by injecting residual nitrogen from the ASU can have a 

number of benefits, depending on the design of the CT: 

• Increased diluent increases mass flow through the turbine, thus increasing the power 

output of the CT while maintaining optimum firing temperatures for syngas operation. 

This is particularly beneficial for locations where the ambient temperature and/or 

elevation are high and the CT would normally operate at reduced output.

• By mixing with the syngas or by being injected directly into the combustor, the diluent 

nitrogen lowers the firing temperature (relative to natural gas) and reduces the formation 

of thermal NOx.

In this report, the ASU nitrogen product was used as the primary diluent with a design target of 

reducing the syngas lower heating value (LHV) to 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). If the 

amount of available nitrogen was not sufficient to meet this target, additional dilution was 

provided through syngas humidification; if still more dilution was required, the third option was 

steam injection.
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3.1.2.2 Air Integration

Integration between the ASU and the CT can be practiced by extracting some, or all, of the 

ASU’s air requirement from the CT. Medium Btu syngas streams result in a higher mass flow 

than natural gas to provide the same heat content to the CT. Some CT designs may need to 

extract air to maintain stable compressor or turbine operation in response to increased fuel flow 

rates. Other CTs may balance air extraction against injection of all of the available nitrogen 

from the ASU. The amount of air extracted can also be varied as the ambient temperature 

changes at a given site to optimize year-round performance. 

An important aspect of air-integrated designs is the need to efficiently recover the heat of 

compression contained in the air extracted from the CT. Extraction air temperature is normally 

in the range of 399 - 454°C (750 - 850°F) and must be cooled to the last stage main air 

compressor discharge temperature prior to admission to the ASU. High-level recovery from the 

extracted air occurs by transferring heat to the nitrogen stream to be injected into the CT with a 

gas-to-gas heat exchanger.

It was not a goal of this project to optimize the integration of the CT and the ASU, although 

several papers have shown that providing 25-30 percent of the ASU air from the turbine 

compressor provides the best balance between maximizing plant output and efficiency without 

compromising plant availability or reliability. (31), (32)

3.1.2.3 Elevated Pressure ASU Experience in Gasification

The Buggenum, Netherlands unit built for Demkolec was the first elevated-pressure, fully 

integrated ASU to be constructed. It was designed to produce up to 1,796 tonnes/day (1,980 tons 

per day [tpd]) of 95 percent purity oxygen for a Shell coal-based gasification unit that fuels a 

Siemens V94.2 CT. In normal operation at the Buggenum plant the ASU receives all of its air 

supply from and sends all residual nitrogen to the CT. (23)

The Polk County, Florida ASU for the Tampa Electric IGCC is also an elevated-pressure, 

95 percent purity oxygen design that provides 1,832 tonnes/day (2,020 tpd) of oxygen to a GEE 

coal-based gasification unit, which fuels a General Electric 7FA CT. All of the nitrogen 

produced in the ASU is used in the CT. The original design did not allow for air extraction from 

the CT. After a CT air compressor failure in January, 2005, a modification was made to allow 

air extraction, which in turn eliminated a bottleneck in ASU capacity and increased overall 

power output. (33)

3.1.2.4 ASU Basis

For this report, air integration is used for the non-carbon capture cases only. In the CO2 capture 

cases, once the syngas is diluted to the target heating value, all of the available combustion air is 

required to maintain mass flow through the turbine and hence maintain power output.

The amount of air extracted from the CT in the non-capture cases is determined through a 

process that includes the following constraints:

• The output of each CT must be maintained at 232 MW

• The diluted syngas must meet heating value requirements specified by a CT vendor, 

which ranged from 4.4-4.7 MJ/Nm3 (119-125 Btu/scf)
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Meeting the above constraints resulted in different levels of air extraction in the three non-carbon 

capture cases as shown in Exhibit 3-1.

Exhibit 3-1 Air extracted from the combustion turbine and supplied to the ASU in non-carbon 

capture cases

Case No. B1A B4A B5A

Gasifier Shell E-GasTM GEE

Air Extracted from Combustion Turbine, % 4.0 4.0 4.0

Air Provided to ASU, % of ASU Total 19.4 18.9 16.8

3.1.2.5 Air Separation Plant Process Description

The air separation plant is designed to produce 95 percent by volume O2 for use in the gasifier

and Claus plant. The ASU is designed with two production trains, one for each gasifier. The air 

compressor is powered by an electric motor. Nitrogen, containing less than 2 percent by volume 

of O2, is recovered, compressed, and used as a diluent in the CT combustor. A process 

schematic of a typical ASU is shown in Exhibit 3-2. (34)

The air feed to the ASU is supplied from two sources. A portion of the air is extracted from the 

compressor of the CT (non-CO2 capture cases only). The remaining air is supplied from a standalone compressor. Air to the stand-alone compressor is first filtered in a suction filter upstream 

of the compressor. This air filter removes particulate, which may tend to cause compressor 

wheel erosion and foul intercoolers. The filtered air is then compressed in the centrifugal 

compressor, with intercooling and aftercooling.
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Exhibit 3-2 Typical ASU process schematic

Source: NETL

Air from the stand-alone compressor is combined with the extraction air, and the combined 

stream is cooled and fed to an adsorbent-based pre-purifier system. The adsorbent removes 

water, CO2, and C4+ saturated hydrocarbons in the air. After passing through the adsorption 

beds, the air is filtered with a dust filter to remove any adsorbent fines that may be present. 

Downstream of the dust filter a small stream of air is withdrawn to supply the instrument air 

requirements of the ASU.

Regeneration of the adsorbent in the pre-purifiers is accomplished by passing a hot nitrogen 

stream through the off-stream bed(s) in a direction counter current to the normal airflow. The 

nitrogen is heated against extraction steam (1.7 MPa [250 psia]) in a shell and tube heat 

exchanger. (34) The regeneration nitrogen drives off the adsorbed contaminants. Following 

regeneration, the heated bed is cooled to near normal operating temperature by passing a cool 

nitrogen stream through the adsorbent beds. The bed is re-pressurized with air and placed on 

stream so that the current on-stream bed(s) can be regenerated.

The air from the pre-purifier is then split into three streams. About 70 percent of the air is fed 

directly to the cold box. About 25 percent of the air is compressed in an air booster compressor. 

This boosted air is then cooled in an aftercooler against cooling water in the first stage and 

against chilled water in the second stage before it is fed to the cold box. The chiller utilizes lowpressure (LP) process steam at 0.3 MPa (50 psia) to drive the absorption refrigeration cycle. The 
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remaining five percent of the air is fed to a turbine-driven, single-stage, centrifugal booster 

compressor. This stream is cooled in a shell and tube aftercooler against cooling water before it 

is fed to the cold box. (34)

All three air feeds are cooled in the cold box to cryogenic temperatures against returning product 

oxygen and nitrogen streams in plate-and-fin heat exchangers. The large air stream is fed 

directly to the first distillation column to begin the separation process. The second largest air 

stream is liquefied against boiling liquid oxygen before it is fed to the distillation columns. The 

third, smallest air stream is fed to the cryogenic expander to produce refrigeration to sustain the 

cryogenic separation process.

Inside the cold box the air is separated into oxygen and nitrogen products. The oxygen product 

is withdrawn from the distillation columns as a liquid and is pressurized by a cryogenic pump. 

The pressurized liquid oxygen is then vaporized against the high-pressure (HP) air feed before 

being warmed to ambient temperature. The gaseous oxygen exits the cold box and is fed to the 

centrifugal compressor with intercooling between each stage of compression. The compressed 

oxygen is then fed to the gasification unit.

Nitrogen is produced from the cold box at two pressure levels. LP nitrogen is split into two 

streams. The majority of the LP nitrogen is compressed and fed to the CT as diluent nitrogen. A 

small portion of the nitrogen is used as the regeneration gas for the pre-purifiers and recombined 

with the diluent nitrogen. A HP nitrogen stream is also produced from the cold box and is 

further compressed before it is also supplied to the CT.

3.1.3 Water Gas Shift Reactors

Selection of Technology 

In the cases with CO2 separation and capture, the gasifier product must be converted to 

hydrogen-rich syngas. The first step is to convert most of the syngas CO to CO2 by reacting the 

CO with water over a bed of catalyst, producing hydrogen (H2) as a byproduct. The H2O:CO 

molar ratio in the shift reaction, shown below, is adjusted to approximately 2:1 by the addition of 

steam to the syngas stream thus promoting a high conversion of CO. In the cases without CO2

separation and capture, CO shift convertors are not required.

Water Gas Shift: CO + H2O ↔ CO2 + H2

The CO shift converter can be located either upstream of the AGR step (sour gas shift) or 

immediately downstream (sweet gas shift). If the CO converter is located downstream of the 

AGR, then the metallurgy of the unit is less stringent but additional equipment must be added to 

the process. This is because the CO converter promotes carbonyl sulfide (COS) hydrolysis 

without a separate catalyst bed. Products from the gasifier are humidified with steam or water 

and contain a portion of the water vapor necessary to meet the water-to-gas criteria at the reactor 

inlet. If the CO converter is located downstream of the AGR, then the gasifier product would 

first have to be cooled and the free water separated and treated. Then additional steam would 

have to be generated and re-injected into the CO converter feed to meet the required water-to-gas 

ratio. Therefore, for this report the CO converter was located upstream of the AGR unit and is 

referred to as SGS.

Process Description - The SGS consists of two paths of parallel fixed-bed reactors arranged in 

series. Two reactors in series are used in each parallel path to achieve sufficient conversion to 
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meet the 90 percent carbon capture target. In the E-GasTM case, a third shift reactor is added to 

each path to increase the CO conversion because of the relatively high amount of CH4 present in 

the syngas. With the third reactor added, carbon capture is 89.9 percent in the E-GasTM case.

Cooling is provided between the series of reactors to control the exothermic temperature rise. 

The parallel set of reactors is required due to the high gas mass flow rate. In all three CO2

capture cases the heat exchanger after the first SGS reactor is used to vaporize water that is then 

used to adjust the syngas H2O:CO ratio to 2:1 on a molar basis. The heat exchanger after the 

second SGS reactor is used to raise intermediate-pressure (IP) steam, which then passes through 

the reheater (RH) section of the HRSG in the GEE and E-GasTM cases, and is used to preheat the 

syngas prior to the first SGS reactor in the Shell case. Approximately 97 percent conversion of 

the CO is achieved in the GEE and Shell cases, and about 98 percent conversion is achieved in 

the E-GasTM case.

3.1.4 Mercury Removal

An IGCC power plant has the potential of removing mercury in a more simple and cost-effective 

manner than conventional plants (e.g., PC). This is because mercury can be removed from the 

syngas at elevated pressure and prior to combustion where syngas volumes are much smaller 

than combusted flue gas volumes in conventional plants. A conceptual design for a sulfurimpregnated, activated carbon bed adsorption system was developed for mercury control. Data 

on the performance of carbon bed systems were obtained from the Eastman Chemical Company, 

which uses carbon beds at its syngas facility in Kingsport, Tennessee. (18) The coal mercury 

content (0.15 ppm dry) and carbon bed removal efficiency (greater than 99 percent) were 

discussed previously in Sections 2.2 and 2.3, respectively. 

Carbon Bed Location – The packed carbon bed vessels are located upstream of the sulfur 

recovery unit (SRU) and syngas enters at a temperature near 38°C (100°F). Consideration was 

given to locating the beds further upstream before the COS hydrolysis unit (in non-CO2 capture 

cases) at a temperature near 204°C (400°F). However, while the mercury removal efficiency of 

carbon has been found to be relatively insensitive to pressure variations, temperature adversely 

affects the removal efficiency. (35) Eastman Chemical also operates their beds ahead of their 

SRU at a temperature of 30°C (86°F). (18) 

Consideration was also given to locating the beds downstream of the SRU. However, it was felt 

that removing the mercury and other contaminants before the SRU would enhance the 

performance of the SRU and increase the life of the various solvents.

Process Parameters – An empty vessel basis gas residence time of approximately 20 seconds 

was used based on Eastman Chemical’s experience. (18) Allowable gas velocities are limited by 

considerations of particle entrainment, bed agitation, and pressure drop. One-foot-per-second 

superficial velocity is in the middle of the range normally encountered (35) and was selected for 

this application. 

The bed density of 30 lb/ft3 was based on the Calgon Carbon Corporation HGR-P sulfurimpregnated pelletized activated carbon. (36) These parameters determined the size of the 

vessels and the amount of carbon required. Each gasifier train has two mercury removal beds

and there are two gasifier trains in each case, resulting in four carbon beds per case.
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Carbon Replacement Time – Eastman Chemicals replaces its bed every 18 to 24 months. (18) 

However, bed replacement is not because of mercury loading, but for other reasons including:

• A buildup in pressure drop

• A buildup of water in the bed

• A buildup of other contaminants

For this report a 24 month carbon replacement cycle was assumed. Under these assumptions, the 

mercury loading in the bed would build up to 0.6 - 1.1 weight percent (wt%). Mercury capacity 

of sulfur-impregnated carbon can be as high as 20 wt%. (37) The mercury laden carbon is 

considered to be a hazardous waste, and the disposal cost estimate reflects this categorization.

3.1.5 Acid Gas Removal (AGR) Process Selection

Gasification of coal to generate power produces a syngas that must be treated prior to further 

utilization. A portion of the treatment consists of AGR and sulfur recovery. This includes all 

sulfur species, but in particular the total of COS and H2S, thereby resulting in stack gas 

emissions of less than 4 ppmv SO2.

3.1.5.1 COS Hydrolysis

The use of COS hydrolysis pretreatment in the feed to the AGR process converts the COS to a 

more easily capturable H2S species. This method was first commercially proven at the 

Buggenum plant, and was also used at both the Tampa Electric and Wabash River IGCC 

projects. Several catalyst manufacturers, including Haldor Topsoe and Porocel, offer a catalyst 

that promotes the COS hydrolysis reaction. The non-carbon capture COS hydrolysis reactor 

designs are based on information from Porocel. In cases with CO2 capture, the SGS reactors 

reduce COS to H2S as discussed in Section 3.1.3.

The COS hydrolysis reaction is equimolar with a slightly exothermic heat of reaction, as shown 

in the following reaction:

COS + H2O ↔ CO2 + H2S

Since the reaction is exothermic, higher conversion is achieved at lower temperatures. However, 

at lower temperatures the reaction kinetics are slower. Based on the feed gas for this evaluation, 

Porocel recommended a temperature of 177 to 204°C (350 to 400°F). Since the exit gas COS 

concentration is critical to the amount of H2S that must be removed with the AGR process, a 

retention time of 50-75 seconds was used to achieve 99.5 percent conversion of the COS. The 

Porocel activated alumina-based catalyst, designated as Hydrocel 640 catalyst, promotes the 

COS hydrolysis reaction without promoting reaction of H2S and CO to form COS and H2.

Although the reaction is exothermic, the heat of reaction is dissipated among the large amount of 

non-reacting components. Therefore, the reaction is essentially isothermal. The product gas, 

now containing less than 4 ppmv of COS, is cooled prior to entering the mercury removal 

process and the AGR.

3.1.5.2 Sulfur Removal

H2S removal generally consists of absorption by a regenerable solvent. The most commonly 

used technique is based on counter current contact with the solvent. Acid-gas-rich solution from 

the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The 
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regenerated lean solution is then cooled and recirculated to the top of the absorber, completing 

the cycle. Exhibit 3-3 is a simplified diagram of the AGR process. (38)

Exhibit 3-3 Flow diagram for a conventional AGR unit

Source: NETL

There are well over 30 AGR processes in common commercial use throughout the oil, chemical, 

and natural gas industries. However, in a 2002 report by SFA Pacific a list of 42 operating and 

planned gasifiers shows that only six AGR processes are represented: Rectisol, Sulfinol, MDEA, 

Selexol, aqueous di-isoproponal (ADIP) amine, and FLEXSORB. (39) These processes can be 

separated into three general types: chemical reagents, physical solvents, and hybrid solvents.

3.1.5.3 AGR/Gasifier Pairings used in Non-capture Cases

There are numerous commercial AGR processes that could meet the sulfur environmental target 

of this report. The most frequently used AGR systems (Selexol, Sulfinol, MDEA, and Rectisol) 

have all been used with the Shell and GEE gasifiers in various applications. Both existing EGasTM gasifiers use MDEA, but could in theory use any of the existing AGR technologies. (38) 

The following selections were made for the AGR process in non-CO2 capture cases:

• GEE gasifier: Selexol was chosen based on the GE gasifier operating at the highest 

pressure (815 psia versus 615 psia for E-GasTM and Shell), which favors the physical 

solvent used in the Selexol process.

• E-GasTM gasifier: Refrigerated MDEA was chosen because the two operating E-GasTM

gasifiers use MDEA and because Chicago Bridge & Iron Company (CB&I) lists MDEA 

as the selected AGR process on their website. (39) Refrigerated MDEA was chosen over 

conventional MDEA because the sulfur emissions environmental target chosen is just 

outside of the range of conventional (higher temperature) MDEA.

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Feed 

Gas

Treated 

Gas

Cooler

Lean 

Solvent

L/R 

Exchanger

Rich Solvent

Absorber

Lean Solvent

Pump

Reboiler

Stripper

Acid 

Gas

Condenser

Feed 

Gas
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• Shell gasifier: The Sulfinol process was chosen for this case because it is a Shell owned 

technology. While the Shell gasifier can and has been used with other AGR processes, it 

was concluded the most likely pairing would be with the Sulfinol process. 

The two-stage Selexol process is used in all three cases that require CO2 capture. According to 

the previously referenced SFA Pacific report, “For future IGCC with CO2 removal for 

sequestration, a two-stage Selexol process presently appears to be the preferred AGR process –

as indicated by ongoing engineering studies at EPRI and by various engineering firms with 

IGCC interests.” (40)

3.1.5.4 AGR used in CO2 Capture Cases

This section provides a brief process description of the two-stage selexol process used for 

capture cases.

Syngas enters the first of two absorbers where H2S is preferentially removed using loaded 

solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the second 

absorber where CO2 is removed using first flash regenerated, chilled solvent followed by 

thermally regenerated solvent added near the top of the column. The treated gas exits the 

absorber and is sent either directly to the CT or is partially humidified prior to entering the CT. 

A portion of the gas can also be used for coal drying, when required.

The amount of hydrogen recovered from the syngas stream is dependent on the Selexol process 

design conditions. In this report, hydrogen recovery is 99.4 percent. The minimal hydrogen slip 

to the CO2 sequestration stream maximizes the overall plant efficiency. The Selexol plant cost 

estimates are based on a plant designed to recover this high percentage of hydrogen.

The CO2 loaded solvent exits the CO2 absorber. A portion is sent to the H2S absorber, a portion 

is sent to a reabsorber, and the remainder is sent to a series of flash drums for regeneration. The 

CO2 product stream is obtained from the three flash drums. After flash regeneration, the solvent 

is chilled and returned to the CO2 absorber.

The rich solvent exiting the H2S absorber is combined with the rich solvent from the reabsorber,

and the combined stream is heated using the lean solvent from the stripper. The hot, rich solvent 

enters the H2S concentrator and partially flashes. The remaining liquid contacts nitrogen from 

the ASU, and a portion of the CO2 along with lesser amounts of H2S and COS are stripped from 

the rich solvent. The stripped gases from the H2S concentrator are sent to the reabsorber where 

the H2S and COS that were co-stripped in the concentrator are transferred to a stream of loaded 

solvent from the CO2 absorber. The clean gas from the reabsorber is combined with the clean 

gas from the H2S absorber and sent to the CT.

The solvent exiting the H2S concentrator is sent to the stripper where the absorbed gases are 

liberated by hot gases flowing up the column from the steam heated reboiler. Water in the 

overhead vapor from the stripper is condensed and returned as reflux to the stripper or exported 

as necessary to maintain the proper water content of the lean solvent. The acid gas from the 

stripper is sent to the Claus plant for further processing. The lean solvent exiting the stripper is 

first cooled by providing heat to the rich solvent, then further cooled by exchange with the 

product gas and finally chilled in the lean chiller before returning to the top of the CO2 absorber.
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3.1.6 Sulfur Recovery/Tail Gas Cleanup Process Selection

Currently, most of the world’s sulfur is produced from the acid gases coming from gas treating. 

The Claus process remains the mainstay for sulfur recovery. Conventional three-stage Claus 

plants, with indirect reheat and feeds with a high H2S content, can approach 98 percent sulfur 

recovery efficiency. However, since environmental regulations have become more stringent, 

sulfur recovery plants are required to recover sulfur with over 99.8 percent efficiency. To meet 

these stricter regulations, the Claus process underwent various modifications and add-ons.

The add-on modification to the Claus plant selected for this report can be considered a separate 

option from the Claus process. In this context, it is often called a tail gas treating unit (TGTU) 

process.

The Claus Process

The Claus process converts H2S to elemental sulfur via the following reactions:

H2S + 3/2 O2 ↔ H2O + SO2

2H2S + SO2 ↔ 2H2O + 3S

The second reaction, the Claus reaction, is equilibrium limited. The overall reaction is:

3H2S + 3/2 O2 ↔ 3H2O + 3S

The sulfur in the vapor phase exists as S2, S6, and S8 molecular species, with the S2 predominant 

at higher temperatures, and S8 predominant at lower temperatures.

A simplified process flow diagram of a typical three-stage Claus plant is shown in Exhibit 3-4.

(40) One-third of the H2S is burned in the furnace with oxygen from the air to give sufficient 

SO2 to react with the remaining H2S. Since these reactions are highly exothermic, a waste heat 

boiler that recovers this heat to generate HP steam usually follows the furnace. Sulfur is 

condensed in a condenser that follows the HP steam recovery section. LP steam is raised in the 

condenser. The tail gas from the first condenser then goes to several catalytic conversion stages, 

usually two to three, where the remaining sulfur is recovered via the Claus reaction. Each 

catalytic stage consists of gas preheat, a catalytic reactor, and a sulfur condenser. The liquid 

sulfur goes to the sulfur pit, while the tail gas proceeds to the incinerator or for further processing 

in a TGTU.

3.1.6.1 Claus Plant Sulfur Recovery Efficiency

The Claus reaction is equilibrium limited, and sulfur conversion is sensitive to the reaction 

temperature. The highest sulfur conversion in the thermal zone is limited to about 75 percent. 

Typical furnace temperatures are in the range of 1093 to 1427°C (2000 to 2600°F), and as the 

temperature decreases, conversion increases dramatically.
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Exhibit 3-4 Typical three-stage Claus sulfur plant

Source: Milton Beychok (41)

Claus plant sulfur recovery efficiency depends on many factors:

• H2S concentration of the feed gas

• Number of catalytic stages

• Gas reheat method

In order to keep Claus plant recovery efficiencies approaching 94 to 96 percent for feed gases 

that contain about 20 to 50 percent H2S, a split-flow design is often used. In this version of the 

Claus plant, part of the feed gas is bypassed around the furnace to the first catalytic stage, while 

the rest of the gas is oxidized in the furnace to mostly SO2. This results in a more stable 

temperature in the furnace.

3.1.6.2 Oxygen-Blown Claus

Large diluent streams in the feed to the Claus plant, such as N2 from combustion air, or a high 

CO2 content in the feed gas, lead to higher cost Claus processes and any add-on or tail gas units. 

One way to reduce diluent flows through the Claus plant and to obtain stable temperatures in the 

furnace for dilute H2S streams is the oxygen-blown Claus process.

The oxygen-blown Claus process was originally developed to increase capacity at existing 

conventional Claus plants and to increase flame temperatures of low H2S content gases. The 

process has also been used to provide the capacity and operating flexibility for sulfur plants 

where the feed gas is variable in flow and composition such as often found in refineries. The 

application of the process has now been extended to grass roots installations, even for rich H2S 

feed streams, to provide operating flexibility at lower costs than would be the case for 

conventional Claus units. At least four of the gasification plants in Europe use oxygen enriched 

Claus units.

Oxygen enrichment results in higher temperatures in the front-end furnace, potentially reaching 

temperatures as high as 1593 to 1649°C (2900 to 3000°F) as the enrichment moves beyond 40 to 

70 vol% O2 in the oxidant feed stream. Although oxygen enrichment has many benefits, its 
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primary benefit for lean H2S feeds is a stable furnace temperature. Sulfur recovery is not 

significantly enhanced by oxygen enrichment. Because the IGCC process already requires an 

ASU, the oxygen-blown Claus plant was chosen for all cases.

3.1.6.3 Tail Gas Treating

In many refinery and other conventional Claus applications, tail gas treating involves the 

removal of the remaining sulfur compounds from gases exiting the SRU. Tail gas from a typical 

Claus process, whether a conventional Claus or one of the extended versions of the process, 

usually contains small but varying quantities of COS, CS2, H2S, SO2, and elemental sulfur 

vapors. In addition, there may be H2, CO, and CO2 in the tail gas. In order to remove the rest of 

the sulfur compounds from the tail gas, all of the sulfur-bearing species must first be converted 

to H2S. Then, the resulting H2S is absorbed into a solvent and the clean gas vented or recycled 

for further processing. The clean gas resulting from the hydrolysis step can undergo further 

cleanup in a dedicated absorption unit or be integrated with an upstream AGR unit. The latter 

option is particularly suitable with physical absorption solvents. The approach of treating the tail 

gas in a dedicated amine absorption unit and recycling the resulting acid gas to the Claus plant is 

the one used by the Shell Claus Off-gas Treating (SCOT) process. With tail gas treatment, Claus 

plants can achieve overall removal efficiencies in excess of 99.9 percent.

In the case of IGCC applications, the tail gas from the Claus plant can be catalytically 

hydrogenated and then recycled back into the system with the choice of location being 

technology dependent, or it can be treated with a SCOT-type process. In each of the seven cases 

the Claus plant tail gas is hydrogenated, water is separated, the tail gas is compressed and then 

returned to the AGR process for further treatment.

3.1.6.4 Flare Stack

A self-supporting, refractory-lined, carbon steel (CS) flare stack is typically provided to combust 

and dispose of unreacted gas during startup, shutdown, and upset conditions. However, in all 

seven cases a flare stack was provided for syngas dumping during startup, shutdown, etc. This 

flare stack eliminates the need for a separate Claus plant flare.

3.1.7 Slag Handling

The slag handling system conveys, stores, and disposes of slag removed from the gasification 

process. Spent material drains from the gasifier bed into a water bath in the bottom of the 

gasifier vessel. A slag crusher receives slag from the water bath and grinds the material into peasized fragments. A slag/water slurry that is between 5 and 10 percent solids leaves the gasifier 

pressure boundary through either a proprietary pressure letdown device (E-GasTM) or through the 

use of lockhoppers (GEE and Shell) to a series of dewatering bins.

The general aspects of slag handling are the same for all three technologies. The slag is 

dewatered, the water is clarified and recycled, and the dried slag is transferred to a storage area 

for disposal. The specifics of slag handling vary among the gasification technologies regarding 

how the water is separated and the end uses of the water recycle streams.

In this report the slag bins were sized for a nominal holdup capacity of 72 hours of full-load 

operation. At periodic intervals, a convoy of slag-hauling trucks will transit the unloading 

station underneath the hopper and remove a quantity of slag for disposal. Approximately ten 

truckloads per day are required to remove the total quantity of slag produced by the plant 
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operating at nominal rated power. While the slag is suitable for use as a component of road

paving mixtures, it was assumed in this report that the slag would be landfilled at a specified 

cost.

3.1.8 Power Island

3.1.8.1 Combustion Turbine 

The CT generator selected for this application is representative of the state-of-the-art 2008 Fclass turbines. This machine is an axial flow, single spool, and constant speed unit, with variable 

inlet guide vane (IGV). The turbine includes advanced bucket cooling techniques, compressor 

aerodynamic design and advanced alloys, enabling a higher firing temperature than the previous 

generation machines. The standard production version of this machine is fired with natural gas 

and is also commercially offered for use with IGCC derived syngas, although only earlier 

versions of the turbine are currently operating on syngas. For the purposes of this report, it was 

assumed that the state-of-the-art 2008 F-class turbine will be commercially available for use on 

both conventional and high hydrogen content syngas representative of the cases with CO2

capture. High H2 fuel combustion issues like flame stability, flashback, and NOx formation were 

assumed to be solved in the time frame needed to support deployment. However, because these 

are FOAK applications, process contingencies were included in the cost estimates as described in 

Section 2.6. Performance typical of a state-of-the-art 2008 F-class turbine on natural gas at ISO 

conditions is presented in Exhibit 3-5. 

Exhibit 3-5 State-of-the-art 2008 F-class combustion turbine performance

characteristics using natural gas (42)

State-of-the-art 2008 

F-Class

Firing Temperature Class, °C (°F) 1,371+ (2,500+)

Airflow, kg/s (lb/s) 431 (950)

Pressure Ratio 18.5

Simple Cycle Output, MW 185

Combined cycle performance

Net Output, MW 280

Net Efficiency (LHV), % 57.5

Net Heat Rate (LHV), kJ/kWh 

(Btu/kWh) 6,256 (5,934)

In this service, with syngas from an IGCC plant, the machine requires some modifications to the 

burner and turbine nozzles in order to properly combust the low-Btu gas and expand the 

combustion products in the turbine section of the machine.

The modifications to the machine include a redesign of the original can-annular combustors. A 

second modification involves increasing the nozzle areas of the turbine to accommodate the mass 

and volume flow of low-Btu fuel gas combustion products, which are increased relative to those 

produced when firing natural gas. Other modifications include rearranging the various auxiliary 

skids that support the machine to accommodate the spatial requirements of the plant’s general 

arrangement. The generator is a standard hydrogen-cooled machine with static exciter.
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3.1.8.2 Combustion Turbine Package Scope of Supply

The CT is typically supplied in several fully shop-fabricated modules, complete with all 

mechanical, electrical, and control systems as required for CT operation. Site CT installation 

involves module inter-connection, and linking CT modules to the plant systems. 

3.1.8.3 CT Firing Temperature Control Issue for Low Calorific Value Fuel

A CT when fired on LCV syngas has the potential to increase power output due to the increase in 

flow rate through the turbine. The higher turbine flow and moisture content of the combustion 

products can contribute to overheating of turbine components, affect rating criteria for the parts 

lives, and require a reduction in syngas firing temperatures (compared to the natural gas firing) to 

maintain design metal temperature. (43) Uncontrolled syngas firing temperature could result in 

more than 50 percent life cycle reduction of stage 1 buckets. Control systems for syngas 

applications include provisions to compensate for these effects by maintaining virtually constant 

generation output for the range of the specified ambient conditions. IGVs and firing temperature 

are used to maintain the turbine output at the maximum torque rating, producing a flat rating up 

to the IGV full open position. Beyond the IGV full open position, flat output may be extended to 

higher ambient air temperatures by steam/nitrogen injection.

In this report the firing temperature (defined as inlet rotor temperature) in the non-capture cases 

is 1333-1343°C (2432-2449°F) and in the CO2 capture cases is 1317-1322°C (2402-2412°F). 

The reduction in firing temperature in the CO2 capture cases is done to maintain parts life as the 

H2O content of the combustion products increases from 6-9 vol% in the non-capture cases to 12-

14 vol% in the capture cases. The decrease in temperature also results in the lower temperature 

steam cycle in the CO2 capture cases, ranging from 12.4 MPa/534°C/534°C (1800 

psig/993°F/993°F) to 12.4 MPa/534°C/534°C (1800 psig/994°F/994°F) for all of the CO2

capture cases versus 12.4 MPa/559°C/559°C (1800 psig/1038°F/1038°F) to 12.4 

MPa/562°C/562°C (1800 psig/1043°F/1043°F) for all of the non-CO2 capture cases.

3.1.8.4 Combustion Turbine Syngas Fuel Requirements 

Typical fuel specifications and contaminant levels for successful CT operation are provided in 

GE Power System’s “Specification for Fuel Gases for Combustion in Heavy-Duty Turbines” and 

presented for state-of-the-art 2008 F-class machines in Exhibit 3-6 and Exhibit 3-7. (44) The vast 

majority of published CT performance information is specific to natural gas operation. Turbine 

performance using syngas requires vendor input as was obtained for this report.

Exhibit 3-6 Typical fuel specification for state-of-the-art 2008 F-class machines

Max Min

LHV, kJ/m3 (Btu/scf) None 3.0 (100)

Gas Fuel Pressure, MPa (psia) 3.1 (450)

Gas Fuel Temperature, °C (°F) A Varies with gas 

pressureB

Flammability Limit Ratio, Rich-to-Lean, 

Volume Basis

C 2:2.1

Sulfur D

A The maximum fuel temperature is defined in GEK-4189 (45)
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B To ensure that the fuel gas supply to the CT is 100 percent free of liquids the minimum fuel gas 

temperature must meet the required superheat over the respective dew point. This requirement is 

independent of the hydrocarbon and moisture concentration. Superheat calculation shall be 

performed as described in GEI-4140G (44) 

C Maximum flammability ratio limit is not defined. Fuel with flammability ratio significantly larger than 

those of natural gas may require start-up fuel

D The quantity of sulfur in syngas is not limited by specification. Experience has shown that fuel 

sulfur levels up to one percent by volume do not significantly affect oxidation/corrosion rates

3.1.8.5 Normal Operation

Inlet air is compressed in a single spool compressor to a pressure ratio of approximately 16:1. 

This pressure ratio was vendor specified and less than the 17:1 ratio used in natural gas 

applications. The majority of compressor discharge air remains on board the machine and passes 

to the burner section to support combustion of the syngas. Compressed air is also used in burner, 

transition, and film cooling services. About 4-7 percent of the compressor air is extracted and 

integrated with the air supply of the ASU in non-carbon capture cases. It may be technically 

possible to integrate the CT and ASU in CO2 capture cases as well; however, in this report

integration was considered only for non-carbon capture cases.

Exhibit 3-7 Allowable gas fuel contaminant level for state-of-the-art 2008 F-class machines

Turbine Inlet 

Limit, ppbw

Fuel Limit, ppmw

Turbine Inlet Flow/Fuel Flow

50 12 4

Lead 20 1.0 0.240 .080

Vanadium 10 0.5 0.120 0.040

Calcium 40 2.0 0.480 0.160

Magnesium 40 2.0 0.480 0.160

Sodium + Potassium

Na/K = 28A 20 1.0 0.240 0.080

Na/K = 3 10 0.5 0.120 0.40

Na/K ≤ 1 6 0.3 0.072 0.024

Particulates TotalB 600 30 7.2 2.4

Above 10 microns 6 0.3 0.072 0.024

ANominal sea salt ratio

BThe fuel gas delivery system shall be designed to prevent generation or admittance of solid 

particulate to the CT gas fuel system

Pressurized syngas is combusted in 14 parallel diffusion combustors, and syngas dilution is used 

to limit NOx formation. As described in Section 3.1.2, nitrogen from the ASU is used as the 

primary diluent followed by syngas humidification and finally by steam dilution, if necessary, to 

achieve an LHV of 4.4-4.7 MJ/Nm3 (119-125 Btu/scf). The advantages of using nitrogen as the 

primary diluent include:

• Nitrogen from the ASU is already partially compressed and using it for dilution 

eliminates wasting the compression energy.
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• Limiting the water content reduces the need to de-rate firing temperature, particularly in 

the high-hydrogen (CO2 capture) cases.

There are some disadvantages to using nitrogen as the primary diluent, and these include:

• There is a significant auxiliary power requirement to further compress the large nitrogen 

flow from the ASU pressures of 0.4 and 1.3 MPa (56 and 182 psia) to the CT pressure of 

3.2 MPa (465 psia).

• Low-quality heat not otherwise useful for other applications can be used to preheat water 

for the syngas humidification process.

• Nitrogen is not as efficient as water in limiting NOx emissions.

It is not clear that one dilution method provides a significant advantage over the other. However, 

in this report nitrogen was chosen as the primary diluent based on suggestions by turbine 

industry experts during peer review of the report.

Hot combustion products are expanded in the three-stage turbine-expander. Given the assumed 

ambient conditions, back-end loss, and HRSG pressure drop, the CT exhaust temperature is 

nominally 588°C (1,090°F) for non-CO2 capture cases and 562°C (1,044°F) for capture cases. 

Gross turbine power, as measured prior to the generator terminals, is 232 MW per train. The CT 

generator is a standard hydrogen-cooled machine with static exciter.

3.1.9 Steam Generation Island

3.1.9.1 Heat Recovery Steam Generator 

The HRSG is a horizontal gas flow, drum-type, multi-pressure design that is matched to the 

characteristics of the CT exhaust gas. High-temperature flue gas exiting the CT is conveyed 

through the HRSG to recover the large quantity of thermal energy that remains. Flue gas travels 

through the HRSG gas path and exits at 132°C (270°F) for all 7 cases.

The HP drum produces steam at main steam pressure, while the IP drum produces process steam 

and turbine dilution steam, if required. The HRSG drum pressures are nominally 12.4/3.1 MPa 

(1,800/443 psia) for the HP/IP turbine sections, respectively. In addition to generating and 

superheating steam, the HRSG performs reheat duty for the cold/hot reheat steam for the steam 

turbine, provides condensate and feedwater (FW) heating, and also provides deaeration of the 

condensate.

Natural circulation of steam is accomplished in the HRSG by utilizing differences in densities 

due to temperature differences of the steam. The natural circulation HRSG provides the most 

cost-effective and reliable design.

The HRSG drums include moisture separators, internal baffles, and piping for FW/steam. All 

tubes, including economizers, superheaters, and headers and drums, are equipped with drains.

Safety relief valves are furnished in order to comply with appropriate codes and ensure a safe 

work place.

Superheater, boiler, and economizer sections are supported by shop-assembled structural steel. 

Inlet and outlet duct is provided to route the gases from the CT outlet to the HRSG inlet and the 

HRSG outlet to the stack. A diverter valve is included in the inlet duct to bypass the gas when 

appropriate. Suitable expansion joints are also included.
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3.1.9.2 Steam Turbine Generator and Auxiliaries

The steam turbine consists of an HP section, an IP section, and one double-flow LP section, all 

connected to the generator by a common shaft. The HP and IP sections are contained in a singlespan, opposed-flow casing, with the double-flow LP section in a separate casing. The LP turbine 

has a last stage bucket length of 76 cm (30 in).

Main steam from the HRSG and gasifier island is combined in a header, and then passes through 

the stop valves and control valves and enters the turbine at either 12.4 MPa/559°C to 562°C 

(1,800 psig/1,038°F to 1,043°F) for the non-carbon capture cases, or 12.4 MPa/534°C (1,800 

psig/993°F to 994°F) for the carbon capture cases. The steam initially enters the turbine near the 

middle of the HP span, flows through the turbine, and returns to the HRSG for reheating. The 

reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 

3.1 MPa/558°C to 561°C (443 psig/1,036°F to 1,041°F) for the non-carbon capture cases or 3.1 

MPa/532°C to 533°C (443 psig/990°F to 992°F) for the carbon capture cases. After passing 

through the IP section, the steam enters a crossover pipe, which transports the steam to the LP 

section. The steam divides into two paths and flows through the LP sections, exhausting 

downward into the condenser.

Turbine bearings are lubricated by a closed-loop (CL), water-cooled, pressurized oil system. The 

oil is contained in a reservoir located below the turbine floor. During startup or unit trip, an 

emergency oil pump mounted on the reservoir pumps the oil. When the turbine reaches 

95 percent of synchronous speed, the main pump mounted on the turbine shaft pumps oil. The 

oil flows through water-cooled heat exchangers prior to entering the bearings. The oil then flows 

through the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in-leakage or steam blowout using a modern positive 

pressure variable clearance shaft sealing design arrangement connected to an LP steam seal 

system. During startup, seal steam is provided from the main steam line. As the unit increases 

load, HP turbine gland leakage provides the seal steam. Pressure-regulating valves control the 

gland header pressure and dump any excess steam to the condenser. A steam packing exhauster 

maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room. 

Any steam collected is condensed in the packing exhauster and returned to the condensate 

system.

The generator is a hydrogen-cooled synchronous type, generating power at 24 kV. A static, 

transformer type exciter is provided. The generator is cooled with a hydrogen gas recirculation 

system using fans mounted on the generator rotor shaft. The heat absorbed by the gas is 

removed as it passes over finned tube gas coolers mounted in the stator frame. Gas is prevented 

from escaping at the rotor shafts by a CL oil seal system. The oil seal system consists of storage 

tank, pumps, filters, and pressure controls, all skid-mounted.

The STG is controlled by a triple-redundant, microprocessor-based electro-hydraulic control 

system. The system provides digital control of the unit in accordance with programmed control 

algorithms, color cathode ray tube (CRT) operator interfacing, and datalink interfaces to the 

balance-of-plant DCS, and incorporates on-line repair capability.

3.1.9.3 Condensate System

The condensate system transfers condensate from the condenser hotwell to the deaerator, through 

the gland steam condenser, gasifier, and the low-temperature economizer section in the HRSG. 
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The system consists of one main condenser; two 50 percent capacity, motor-driven, vertical 

condensate pumps; one gland steam condenser; and a low-temperature tube bundle in the HRSG. 

Condensate is delivered to a common discharge header through separate pump discharge lines, 

each with a check valve and a gate valve. A common minimum flow recirculation line 

discharging to the condenser is provided to maintain minimum flow requirements for the gland 

steam condenser and the condensate pumps. 

3.1.9.4 Feedwater System

The function of the FW system is to pump the various FW streams from the deaerator storage 

tank in the HRSG to the respective steam drums. Two 50 percent capacity boiler feed pumps are 

provided for each of 3 pressure levels, HP, IP, and LP. Each pump is provided with inlet and 

outlet isolation valves, and outlet check valve. Minimum flow recirculation to prevent 

overheating and cavitation of the pumps during startup and low loads is provided by an 

automatic recirculation valve and associated piping that discharges back to the deaerator storage 

tank. Pneumatic flow control valves control the recirculation flow. 

The FW pumps are supplied with instrumentation to monitor and alarm on low oil pressure, or 

high-bearing temperature. FW pump suction pressure and temperature are also monitored. In 

addition, the suction of each boiler feed pump is equipped with a startup strainer.

3.1.9.5 Main and Reheat Steam Systems

The function of the main steam system is to convey main steam generated in the synthesis gas 

cooler (SGC) and HRSG from the HRSG superheater outlet to the HP turbine stop valves. The 

function of the reheat system is to convey steam from the HP turbine exhaust to the HRSG RH, 

and to the turbine reheat stop valves.

Main steam at approximately 12.4 MPa/559°C to 562°C (1,800 psig/1,038°F to 1,043°F) (nonCO2 capture cases) or 12.4 MPa/534°C (1,800 psig/993°F to 994°F) (CO2 capture cases) exits 

the HRSG superheater through a motor-operated stop/check valve and a motor-operated gate 

valve, and is routed to the HP turbine. Cold reheat steam at approximately 3.5 MPa/349°C to 

372°C (501 psia/661°F to 702°F) exits the HP turbine, flows through a motor-operated isolation 

gate valve, to the HRSG reheater. Hot reheat steam at approximately 3.1 MPa/558 to 561°C 

(443 psig/1,036°F to 1,041°F) for the non-carbon capture cases and 3.1 MPa/532°C to 533°C 

(443 psig/990°F to 992°F) for the CO2 capture cases exits the HRSG RH through a motoroperated gate valve and is routed to the IP turbines.

Steam piping is sloped from the HRSG to the drip pots located near the steam turbine for 

removal of condensate from the steam lines. Condensate collected in the drip pots and in lowpoint drains is discharged to the condenser through the drain system.

Steam flow is measured by means of flow nozzles in the steam piping. The flow nozzles are 

located upstream of any branch connections on the main headers.

Safety valves are installed to comply with appropriate codes and to ensure the safety of 

personnel and equipment.

3.1.9.6 Circulating Water System

The circulating water system (CWS) is a closed-cycle cooling water system that supplies cooling 

water to the condenser to condense the main turbine exhaust steam. The system also supplies 

cooling water to the AGR plant as required, and to the auxiliary cooling system. The auxiliary 
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cooling system is a CL process that utilizes a higher quality water to remove heat from 

compressor intercoolers, oil coolers, and other ancillary equipment and transfers that heat to the 

main circulating cooling water system in plate and frame heat exchangers. The heat transferred 

to the circulating water in the condenser and other applications is removed by a mechanical draft 

cooling tower.

The system consists of two 50 percent capacity vertical CWPs, a mechanical draft evaporative 

cooling tower, and CS cement-lined interconnecting piping. The pumps are single-stage vertical 

pumps. The piping system is equipped with butterfly isolation valves and all required expansion 

joints. The cooling tower is a multi-cell wood frame counterflow mechanical draft cooling 

tower.

The condenser is a single-pass, horizontal type with divided water boxes. There are two separate 

circulating water circuits in each box. One-half of the condenser can be removed from service 

for cleaning or for plugging tubes. This can be done during normal operation at reduced load.

The condenser is equipped with an air extraction system to evacuate the condenser steam space 

for removal of non-condensable gases during steam turbine operation and to rapidly reduce the 

condenser pressure from atmospheric pressure before unit startup and admission of steam to the 

condenser.

3.1.9.7 Raw Water, Fire Protection, and Cycle Makeup Water Systems

The raw water system supplies cooling tower makeup, cycle makeup, service water and potable 

water requirements. The water source is 50 percent from a POTW and 50 percent from 

groundwater. Booster pumps within the plant boundary provide the necessary pressure.

The fire protection system provides water under pressure to the fire hydrants, hose stations, and 

fixed water suppression system within the buildings and structures. The system consists of

pumps, underground and aboveground supply piping, distribution piping, hydrants, hose stations, 

spray systems, and deluge spray systems. One motor-operated booster pump is supplied on the 

intake structure of the cooling tower with a diesel engine backup pump installed on the water 

inlet line.

The cycle makeup water system provides high-quality demineralized water for makeup to the 

HRSG cycle, for steam injection ahead of the SGS reactors in CO2 capture cases, and for 

injection steam to the auxiliary boiler for control of NOx emissions, if required.

The cycle makeup system consists of two 100 percent trains, each with a full-capacity activated 

carbon filter, primary cation exchanger, primary anion exchanger, mixed bed exchanger, recycle 

pump, and regeneration equipment. The equipment is skid-mounted and includes a control panel 

and associated piping, valves, and instrumentation.

3.1.10 Accessory Electric Plant

The accessory electric plant consists of switchgear and control equipment, generator equipment, 

station service equipment, conduit and cable trays, and wire and cable. It also includes the main 

power transformer, all required foundations, and standby equipment.
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3.1.11 Waste Treatment/Miscellaneous Systems

An onsite water treatment facility treats all runoff, cleaning wastes, blowdown, and backwash. It 

is anticipated that the treated water will be suitable for discharge into existing systems and be 

within the EPA standards for suspended solids, oil and grease, pH, and miscellaneous metals.

The waste treatment system is minimal and consists, primarily, of neutralization and oil/water 

separators (along with the associated pumps, piping, etc.). 

A natural gas supply line has been included in all cases for start-up or emergency fuel.

Miscellaneous systems consisting of natural gas, service air, instrument air, and service water are 

provided. A natural gas supply line has been included in all cases for start-up or emergency fuel. 

All truck roadways and unloading stations inside the fence area are provided.

3.1.12 Instrumentation and Control

An integrated plant-wide distributed control system (DCS) is provided. The DCS is a redundant 

microprocessor-based, functionally DCS. The control room houses an array of multiple video 

monitor (CRT) and keyboard units. The CRT/keyboard units are the primary interface between 

the generating process and operations personnel. The DCS incorporates plant monitoring and 

control functions for all the major plant equipment. The DCS is designed to be operational and 

accessible 99.5 percent of the time that it is required (99.5 percent availability). The plant 

equipment and the DCS are designed for automatic response to load changes from minimum load 

to 100 percent. Startup and shutdown routines are manually implemented, with operator 

selection of modular automation routines available. The exception to this, and an important facet 

of the control system for gasification, is the critical controller system, which is a part of the 

license package from the gasifier supplier and is a dedicated and distinct hardware segment of 

the DCS.

This critical controller system is used to control the gasification process. The partial oxidation of 

the fuel feed and oxygen feed streams to form a syngas product is a stoichiometric, temperatureand pressure-dependent reaction. The critical controller utilizes a redundant microprocessor 

executing calculations and dynamic controls at 100- to 200-millisecond intervals. The enhanced 

execution speeds as well as evolved predictive controls allow the critical controller to mitigate 

process upsets and maintain the reactor operation within a stable set of operating parameters.

3.1.13 Performance Summary Metrics

This section details the methodologies of several metrics reported in the performance summaries.

Cold Gas Efficiency

The cold gas efficiency is calculated by subtracting the heating value of any gas recycled to the 

gasifier from the heating value of the gas exiting the gasifier and dividing that difference by the 

thermal input to the gasifier. This calculation is represented by the equation:

CCCC = ( − RRRR)

TT

Where:

CGE – cold gas efficiency

GO – heating value of gas exiting the gasifier

RI – heating value of gas recycled to gasifier
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TI – thermal input to into the gasifier

The thermal input to the gasifier is calculated by taking the coal feed rate and multiplying by the 

heating value and converting the units to kW.

The components considered for the heating value of the gasifier exit gas and recycle gas are CO, 

H2, CH4, H2S, NH3, and COS. Their mole fraction is extracted from the model, multiplied by the 

molar flow of the stream, and then multiplied by their individual heating values.

Combustion Turbine Efficiency

The combustion turbine efficiency is calculated by taking the combustion turbine power 

produced and dividing it by the thermal input to the turbines. This calculation is represented by 

the equation:

CC = CC CC

TT

Where:

CTE – combustion turbine efficiency

CTP – combustion turbine power

TI – thermal input to turbines

The thermal input is calculated by taking the mole fraction of the individual gases (CO, H2, CH4, 

H2S, NH3, and COS) multiplied by the molar flow rate of the total stream entering the 

combustion turbine and then multiplying each by their individual heating values.

Steam Turbine Efficiency

The steam turbine efficiency is calculated by taking the steam turbine power produced and 

dividing it by the difference between the thermal input and thermal output. This calculation is 

represented by the equation:

SS = SS

(TT − TT )

Where:

STE – steam turbine efficiency

STP – steam turbine power

TI – thermal input

TO – thermal output

The thermal input is considered to be the main steam, the makeup water, and the low pressure 

steam from the BFW.

The thermal output is considered to be any extractions such as the gasifier steam, the 250 psia 

header, and the BFW from the condenser.

The IP blowdown, HP blowdown, and superheater losses are also credited to the thermal input as 

they are extracted from the cycle prior to the main steam but after the condensate BFW.

Steam Turbine Heat Rate

The steam turbine heat rate is calculated by taking the inverse of the steam turbine efficiency.

This calculation is represented by the equation:

SS SS = 1

SS ∗ 3,412
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Where:

STHR – steam turbine heat rate, Btu/kWh

STE – steam turbine efficiency, fraction

3.2 Shell Global Solutions IGCC Cases

This section contains an evaluation of plant designs for cases B1A and B1B, which are based on 

the Shell gasifier. Cases B1A and B1B are very similar in terms of process, equipment, scope 

and arrangement, except that Case B1B employs a syngas quench and includes SGS reactors, 

CO2 absorption/regeneration, and compression/transport systems. There are no provisions for 

CO2 removal in Case B1A.

The balance of this section is organized as follows:

• Gasifier Background – provides information on the development and status of the Shell 

gasification technology.

• Process and System Description – provides an overview of the technology operation as

applied to Case B1A. The systems that are common to all gasifiers were covered in 

Section 3.1 and only features that are unique to Case B1A are discussed further in this 

section.

• Key Assumptions – provides a summary of study and modeling assumptions relevant to 

cases B1A and B1B.

• Sparing Philosophy – provided for cases B1A and B1B

• Performance Results – provides the main modeling results from Case B1A, including the 

performance summary, environmental performance, carbon balance, sulfur balance, water 

balance, mass and energy balance diagrams, and mass and energy balance tables.

• Equipment List – provides an itemized list of major equipment for Case B1A with 

account codes that correspond to the cost accounts in the Cost Estimates section.

• Cost Estimates – provides a summary of capital and operating costs for Case B1A.

Process and System Description, Performance Results, Equipment List and Cost Estimates are 

repeated for Case B1B.

3.2.1 Gasifier Background

The “Coal Gasification Guidebook: Status, Application, and Technologies” report published by 

the EPRI provides a detailed history of the development of several types of gasifier technology, 

including the Shell gasifier, as well as gasifier capacity, distinguishing characteristics, and 

important coal characteristics. (46)

As of 2009, Shell reported ten gasifiers in operation producing 100,000-150,000 Nm3

/hr and 

three of the same size in construction. Another three ranging from 150,000-250,000 Nm3/hr are 

also in construction. (47) The large gasifier operating in The Netherlands has a bituminous coalhandling capacity of 1,633 tonnes/day (1,800 tpd) and produces dry gas at a rate of 158,575 

Nm3

/hr (5.6 million scf/hr) with an energy content of about 1,792 GJ/hr (1,700 MMBtu/hr) 

(HHV). This gasifier was sized to match the fuel gas requirements for the Siemens/Kraftwerk 

Union V-94.2 CT and could easily be scaled up to match state-of-the-art 2008 F-class turbine 

requirements. (47)
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Shell gasifiers are capable of utilizing a wide variety of coal types, and compared to slurry fed 

gasifiers, the dry-fed, cooled-refractory lined, Shell gasifier has a lower oxygen requirement and 

produces a gas with a higher H2S/CO2 ratio, which improves sulfur recovery. (46)

While the use of dry feed allows for lower oxygen consumption, the feed system – which 

includes the coal drying system – is more costly and complicated. (46)

Coal characteristics that are favorable when selecting a coal type for use with a Shell gasifier 

include low concentrations of ash with a moderate fusion temperature. If a coal is selected that 

has a high ash fusion temperature, flux addition may be necessary. The negative impact that 

high ash coals have on the operation of gasifiers are reduced in dry feed systems in comparison 

to slurry fed gasifiers. (46)

3.2.2 Process Description

In this section the overall Shell gasification process for Case B1A is described. The system 

description follows the block flow diagram (BFD) in Exhibit 3-8 and stream numbers reference 

the same exhibit. The tables in Exhibit 3-9 provide process data for the numbered streams in the 

BFD.

3.2.2.1 Coal Preparation and Feed Systems

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. The Shell process uses a dry feed 

system, which is sensitive to the coal moisture content. Coal moisture consists of two parts, 

surface moisture and inherent moisture. For coal to flow smoothly through the lock hoppers, the 

surface moisture must be removed. The Illinois No. 6 coal used in this report contains 

11.12 percent total moisture on an as-received basis (stream 9). It was assumed that the coal 

must be dried to 5 percent moisture to allow for smooth flow through the dry feed system 

(stream 10).

The coal is simultaneously crushed and dried in the coal mill then delivered to a surge hopper 

with an approximate 2-hour capacity. The drying medium is provided by combining the off-gas 

from the Claus plant TGTU and a slipstream of clean syngas (stream 8) and passing them 

through an incinerator. The incinerator flue gas, with an oxygen content of 6 vol%, is then used 

to dry the coal in the mill.

The coal is drawn from the surge hoppers and fed through a pressurization lock hopper system to 

a dense phase pneumatic conveyor, which uses nitrogen from the ASU to convey the coal to the 

gasifiers.
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Exhibit 3-8 Case B1A block flow diagram, Shell IGCC without CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

DUCT/SYNGAS

COOLERS

GAS COOLING

BFW HEATING

& KNOCKOUT

SCRUBBER

& COS

HYDROLYSIS

ELEVATED

PRESSURE

ASU

SHELL GASIFIER

MERCURY

REMOVAL

SULFINOL CLAUS

PLANT

SYNGAS

REHEAT

HRSG

2X STATE-OF-THEART F-CLASS

GAS TURBINES

1

AIR TO ASU

2 3

VENT

GAS

5

10 11

GASIFIER

OXIDANT

DRY

COAL SLAG

14 15

20

21

19

4

23

24

TURBINE COOLING AIR

25

AMBIENT AIR

FLUE GAS STACK GAS

HYDROGENATION

REACTOR AND GAS

COOLER

22

CLEAN

GAS

NITROGEN DILUENT

AIR

SULFUR

PRODUCT

SYNGAS

COAL

DRYER

DRYING

GAS

PREP

9

WET

COAL

17

8

6

13

12

AIR

SYNGAS

SYNGAS QUENCH

RECYCLE

TO SOUR

WATER

STRIPPER

ACID GAS

STEAM

SYNGAS

HUMIDIFICATION

18

7 TRANSPORT

NITROGEN

C 26 LAUS

PLANT

OXIDANT

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

Note: Block Flow Diagram is not intended to 27

represent a complete material balance. Only 

major process streams and equipment are 

shown.

16
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Exhibit 3-9 Case B1A stream table, Shell IGCC without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0262 0.0318 0.0023 0.0318 0.0000 0.0023 0.0100 0.0000 0.0000 0.0000 0.0095 0.0095 0.0096

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0006 0.0006 0.0006

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.5980 0.0000 0.0000 0.0000 0.5797 0.5797 0.5833

CO2 0.0003 0.0092 0.0000 0.0000 0.0000 0.0000 0.0000 0.0158 0.0000 0.0000 0.0000 0.0143 0.0143 0.0151

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0007 0.0007 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3142 0.0000 0.8090 0.0000 0.3006 0.3006 0.3024

H2O 0.0099 0.2378 0.0000 0.0003 0.0000 1.0000 0.0004 0.0013 0.0000 0.0935 0.0000 0.0252 0.0252 0.0194

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0009 0.0009 0.0001

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0081 0.0081 0.0089

N2 0.7732 0.5018 0.0178 0.9919 0.0178 0.0000 0.9919 0.0601 0.0000 0.0163 0.0000 0.0567 0.0567 0.0570

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0036 0.0036 0.0036

O2 0.2074 0.2251 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 18,364 812 88 16,375 4,591 1,061 882 252 0 0 0 25,096 17,567 17,460

V-L Flowrate (kg/hr) 529,935 21,917 2,828 459,480 147,752 19,111 24,747 5,088 0 0 0 509,993 356,995 354,790

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 198,059 185,222 19,837 0 0 0

Temperature (°C) 15 21 32 93 32 343 32 45 15 16 1,427 1,079 191 177

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.41 3.65 0.10 5.79 4.24 4.24 4.03 3.90

Steam Table Enthalpy (kJ/kg)A 30.23 37.32 26.67 92.52 26.67 3,063.97 21.22 60.75 --- --- --- 1,749.13 330.23 297.65

AspenPlus Enthalpy (kJ/kg)B -97.58 -2,651.61 4.13 63.38 4.13 -12,907.38 -8.35 -3,577.38 -2,116.95 -768.33 2,165.43 -2,101.56 -3,520.45 -3,497.87

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 20.1 60.5 27.8 --- 16.5 --- 7.6 21.0 20.9

V-L Molecular Weight 28.857 26.992 32.181 28.060 32.181 18.015 28.060 20.195 --- --- --- 20.322 20.322 20.320

V-L Flowrate (lbmole/hr) 40,486 1,790 194 36,101 10,122 2,339 1,944 555 0 0 0 55,328 38,729 38,493

V-L Flowrate (lb/hr) 1,168,307 48,319 6,236 1,012,980 325,738 42,132 54,557 11,218 0 0 0 1,124,342 787,039 782,178

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 436,646 408,345 43,732 0 0 0

Temperature (°F) 59 70 90 199 90 650 90 112 59 60 2,600 1,974 375 351

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 785.0 530.0 14.7 840.0 615.0 615.0 585.0 565.0

Steam Table Enthalpy (Btu/lb)A 13.0 16.0 11.5 39.8 11.5 1,317.3 9.1 26.1 --- --- --- 752.0 142.0 128.0

AspenPlus Enthalpy (Btu/lb)B -42.0 -1,140.0 1.8 27.2 1.8 -5,549.2 -3.6 -1,538.0 -910.1 -330.3 931.0 -903.5 -1,513.5 -1,503.8

Density (lb/ft3) 0.076 0.101 0.687 1.521 0.687 1.257 3.774 1.734 --- 1.029 --- 0.475 1.310 1.303

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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Exhibit 3-9 Case B1A stream table, Shell IGCC without capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27

V-L Mole Fraction

Ar 0.0098 0.0098 0.0100 0.0079 0.0079 0.0004 0.0000 0.0058 0.0092 0.0092 0.0086 0.0086 0.0000

CH4 0.0006 0.0006 0.0006 0.0005 0.0005 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.5962 0.5845 0.5980 0.4741 0.4741 0.0167 0.0000 0.1034 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0155 0.0257 0.0158 0.0125 0.0125 0.4460 0.0000 0.2613 0.0003 0.0003 0.0752 0.0752 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.3091 0.3072 0.3142 0.2491 0.2491 0.0096 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0014 0.0015 0.0013 0.2083 0.2083 0.0063 0.0000 0.4259 0.0099 0.0099 0.0906 0.0906 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0091 0.0089 0.0000 0.0000 0.0000 0.3872 0.0000 0.0016 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0583 0.0618 0.0601 0.0476 0.0476 0.1338 0.0000 0.1585 0.7732 0.7732 0.7210 0.7210 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1046 0.1046 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 17,081 17,426 16,771 21,155 21,155 402 0 510 110,253 4,410 137,428 137,428 39,521

V-L Flowrate (kg/hr) 347,994 358,740 338,688 417,666 417,666 14,964 0 13,723 3,181,557 127,262 3,962,154 3,962,154 711,987

Solids Flowrate (kg/hr) 0 0 0 0 0 0 4,959 0 0 0 0 0 0

Temperature (°C) 35 34 45 161 193 45 178 232 15 432 587 132 559

Pressure (MPa, abs) 3.72 3.69 3.65 3.21 3.17 3.65 0.41 0.41 0.10 1.62 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 45.28 44.26 60.75 710.39 762.94 13.88 --- 1,007.13 30.23 463.79 791.04 280.13 3,496.26

AspenPlus Enthalpy (kJ/kg)B -3,555.60 -3,652.99 -3,577.38 -5,259.88 -5,207.33 -5,041.46 142.76 -7,809.89 -97.58 335.98 -1,163.40 -1,674.31 -12,474.05

Density (kg/m3) 29.5 29.6 27.8 17.7 16.2 60.9 5,278.6 2.6 1.2 7.9 0.4 0.9 35.2

V-L Molecular Weight 20.373 20.587 20.195 19.743 19.743 37.190 --- 26.923 28.857 28.857 28.831 28.831 18.015

V-L Flowrate (lbmole/hr) 37,657 38,417 36,974 46,639 46,639 887 0 1,124 243,066 9,723 302,978 302,978 87,130

V-L Flowrate (lb/hr) 767,195 790,887 746,680 920,796 920,796 32,989 0 30,253 7,014,133 280,565 8,735,054 8,735,054 1,569,663

Solids Flowrate (lb/hr) 0 0 0 0 0 0 10,933 0 0 0 0 0 0

Temperature (°F) 94 94 112 321 380 112 353 450 59 810 1,088 270 1,038

Pressure (psia) 540.0 535.0 530.0 465.0 460.0 530.0 59.3 58.9 14.7 234.9 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 19.5 19.0 26.1 305.4 328.0 6.0 --- 433.0 13.0 199.4 340.1 120.4 1,503.1

AspenPlus Enthalpy (Btu/lb)B -1,528.6 -1,570.5 -1,538.0 -2,261.3 -2,238.7 -2,167.4 61.4 -3,357.6 -42.0 144.4 -500.2 -719.8 -5,362.9

Density (lb/ft3) 1.844 1.850 1.734 1.103 1.011 3.805 329.535 0.163 0.076 0.495 0.026 0.056 2.200

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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3.2.2.2 Gasifier

There are two Shell dry feed, pressurized, upflow, entrained, slagging gasifiers, operating at 4.2 

MPa (615 psia) and processing a total of 4,753 tonnes/day (5,240 tpd) of as-received coal. The 

air separation plant supplies 3,614 tonnes/day (3,984 tpd) of 95 percent oxygen to the gasifiers 

(stream 5) and the Claus plant (stream 3). Coal reacts with oxygen and steam at a temperature of 

1427°C (2600°F) in the gasifier to produce principally hydrogen and carbon monoxide with little 

carbon dioxide formed. 

The gasifier’s refractory-lined water wall is protected by molten slag that solidifies on the cooled 

walls. 

3.2.2.3 Raw Gas Cooling/Particulate Removal

High-temperature heat recovery in each gasifier train is accomplished in three steps, including 

the gasifier jacket, which cools and solidifies slag touching the gasifier walls and maintains the 

syngas temperature at 1,427°C (2,600°F). The product gas from the gasifier is cooled to 

approximately 1,093°C (2,000°F) by adding cooled recycled fuel gas to lower the temperature 

below the ash melting point. Gas (stream 12) then goes through a duct cooler and syngas cooler, 

which lower the gas temperature from approximately 1,093°C (2,000°F) to 316°C (600°F), and 

produce HP steam for use in the steam cycle. 

After passing through the duct cooler and syngas cooler, the syngas passes through a cyclone and 

a raw gas candle filter where a majority of the fine particles are removed and returned to the 

gasifier with the coal fuel. The filter consists of an array of ceramic candle elements in a 

pressure vessel. Fines produced by the gasification system are recirculated to extinction. The 

ash that is not carried out with the gas forms slag and runs down the interior walls, exiting the 

gasifier in liquid form. The slag is solidified in a quench tank for disposal (stream 11). 

Lockhoppers are used to reduce the pressure of the solids from 4.2 to 0.1 MPa (615 to 15 psia). 

The syngas scrubber removes additional PM further downstream.

After passing through the cyclone and ceramic candle filter array, the syngas is further cooled to 

191°C (375°F) (stream 13) by raising IP steam.

3.2.2.4 Quench Gas Compressor

About 30 percent of the cooled syngas is recycled back to the gasifier exit as quench gas. A 

single-stage compressor is utilized to boost the pressure of the cooled fuel gas stream from 4.0 

MPa (575 psia) to 4.0 MPa (585 psia) to provide quench gas to cool the syngas stream from the 

gasifier.

3.2.2.5 Syngas Scrubber/Sour Water Stripper

The raw syngas exiting the final raw gas cooler at 191°C (375°F) (stream 13) then enters the 

scrubber for removal of chlorides, SO2, NH3 and remaining particulate. The quench scrubber 

washes the syngas in a counter-current flow in two packed beds. The syngas leaves the scrubber 

saturated at a temperature of 94°C (201oF). The quench scrubber removes essentially all traces 

of entrained particles, principally unconverted carbon, slag, and metals. The bottoms from the 

scrubber are sent to the sour water stripper for processing.

The sour water stripper removes NH3, SO2, and other impurities from the waste stream of the 

scrubber. The sour gas stripper consists of a sour drum that accumulates sour water from the gas 
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scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which 

consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid 

and sent to the SRU. Remaining water is sent to wastewater treatment.

3.2.2.6 COS Hydrolysis, Mercury Removal and AGR

H2S and COS are at significant concentrations, requiring removal for the power plant to achieve 

the low design level of SO2 emissions. H2S is removed in an AGR process; however, because 

COS is not readily removable, it is first catalytically converted to H2S in a COS hydrolysis unit.

Following the water scrubber, the gas is reheated to 177°C (350°F) and fed to the COS 

hydrolysis reactor. The COS in the sour gas is hydrolyzed with steam over a catalyst bed to H2S, 

which is more easily removed by the AGR solvent. Before the raw fuel gas can be treated in the 

AGR process (stream 14), it must be cooled to about 35°C (95°F). During this cooling through a 

series of heat exchangers, part of the water vapor condenses. This water, which contains some 

NH3, is sent to the sour water stripper. The cooled syngas (stream 15) then passes through a 

series of 2 carbon beds to remove greater than 95 percent of the Hg (Section 3.1.4).

The Sulfinol process, developed by Shell in the early 1960s, is a combination process that uses a 

mixture of amines and a physical solvent. The solvent consists of an aqueous amine and 

sulfolane. Sulfinol-D uses diisopropanolamine (DIPA), while Sulfinol-M uses MDEA. The 

mixed solvents allow for better solvent loadings at high acid gas partial pressures and higher 

solubility of COS and organic sulfur compounds than straight aqueous amines. Sulfinol-M was 

selected for this application. 

The sour syngas is fed directly into an HP contactor. The HP contactor is an absorption column 

in which the H2S, COS, CO2, and small amounts of H2 and CO are removed from the gas by the 

Sulfinol solvent. The overhead gas stream from the HP contactor is then washed with water in 

the sweet gas scrubber before leaving the unit as the feed gas to the sulfur polishing unit.

The rich solvent from the bottom of the HP contactor flows through a hydraulic turbine and is 

flashed in the rich solvent flash vessel. The flashed gas is then scrubbed in the LP contactor with 

lean solvent to remove H2S and COS. The overhead from the LP contactor is flashed in the LP 

KO drum. This gas can be used as a utility fuel gas, consisting primarily of H2 and CO, at 

0.8 MPa (118 psia) and 38°C (101°F). The solvent from the bottom of the LP contactor is 

returned to the rich solvent flash vessel.

Hot, lean solvent in the lean/rich solvent exchanger then heats the flashed rich solvent before 

entering the stripper. The stripper strips the H2S, COS, and CO2 from the solvent at LP with heat 

supplied through the stripper reboiler. The acid gas stream to sulfur recovery/tail gas cleanup is 

recovered as the flash gas from the stripper accumulator. The lean solvent from the bottom of 

the stripper is cooled in the lean/rich solvent exchanger and the lean solvent cooler. Most of the 

lean solvent is pumped to the HP contactor. A small amount goes to the LP contactor.

The Sulfinol process removes essentially all of the CO2 along with the H2S and COS. The acid 

gas fed to the SRU contains 39 vol% H2S and 45 vol% CO2. The CO2 passes through the SRU, 

the TGTU and ultimately is vented through the coal dryer. Since the amount of CO2 in the 

syngas is initially small, this does not have a significant effect on the mass flow reaching the CT. 

However, the costs of the sulfur recovery/tail gas cleanup are higher than that for a sulfur 

removal process producing an acid gas stream with a higher sulfur concentration.
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3.2.2.7 Claus Unit

The SRU is a Claus bypass type SRU utilizing oxygen (stream 3) instead of air. The Claus plant 

produces molten sulfur (stream 21) by reacting approximately one third of the H2S in the feed to 

SO2, then reacting the H2S and SO2 to sulfur and water. The use of Claus technology results in 

an overall sulfur recovery exceeding 99 percent. 

Utilizing oxygen instead of air in the Claus plant reduces the overall cost of the sulfur recovery 

plant. The sulfur plant produces approximately 119 tonnes/day (131 tpd) of elemental sulfur. 

Feed for this case consists of acid gas from both the acid gas cleanup unit (stream 20) and a vent 

stream from the sour water stripper in the gasifier section. A slipstream of clean syngas (stream 

8) is passed through an incinerator and combusted with air. The hot, nearly inert incinerator off 

gas is used to dry coal before being vented to the atmosphere.

In the furnace waste heat boiler, 11,991 kg/hr (26,435 lb/hr) of 3.0 MPa (430 psia) steam is 

generated. This steam is used to satisfy all Claus process preheating and reheating requirements 

as well as to provide some steam to the medium-pressure steam header. The sulfur condensers 

produce 0.34 MPa (50 psig) steam for the LP steam header.

3.2.2.8 Power Block

Clean syngas exiting the Sulfinol absorber (stream 17) is humidified because there is not 

sufficient nitrogen from the ASU to provide the level of dilution required. The moisturized 

syngas (stream 18) is reheated (stream 19), further diluted with nitrogen from the ASU (stream 

4) and steam, and enters the state-of-the-art 2008 F-class CT burner. The CT compressor 

provides combustion air to the burner and also 19 percent of the air requirements in the ASU 

(stream 24). The exhaust gas exits the CT at 587°C (1,088°F) (stream 25) and enters the HRSG 

where additional heat is recovered until the flue gas exits the HRSG at 132°C (270°F) (stream 

26) and is discharged through the plant stack. The steam raised in the HRSG is used to power an 

advanced, commercially available steam turbine using a 12.4 MPa/559°C/559°C (1,800 

psig/1,038°F/1,038°F) steam cycle.

3.2.2.9 Air Separation Unit (ASU)

The ASU is designed to produce a nominal output of 3,614 tonnes/day (3,984 tpd) of 95 mol% 

O2 for use in the gasifier (stream 5) and SRU (stream 3). The plant is designed with two 

production trains. The air compressor is powered by an electric motor. Approximately 11,028 

tonnes/day (12,156 tpd) of nitrogen are also recovered, compressed, and used as dilution in the 

CT combustor. About 4 percent of the CT air is used to supply approximately 19 percent of the 

ASU air requirements, in the non-capture case.

3.2.2.10 Balance of Plant

Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.12.

3.2.3 Key System Assumptions

System assumptions for Cases B1A and B1B (Shell IGCC with and without CO2 capture) are 

compiled in Exhibit 3-10.

3.2.3.1 Balance of Plant – Cases B1A and B1B

The balance of plant assumptions are common to all cases and presented in Exhibit 3-11.
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Exhibit 3-10 Shell IGCC plant study configuration matrix

Case B1A B1B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.84 0.84

Carbon Conversion, % 99.5 99.5

Syngas HHV at Gasifier Outlet, kJ/Nm3

(Btu/scf) 10,841 (291) 10,849 (291)

Steam Cycle, MPa/°C/°C (psig/°F/°F) 12.4/559/559 

(1,800/1,038/1,038)

12.4/534/534 

(1,800/993/993)

Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT

2x State-of-the-art 2008 

F-Class

(232 MW output each)

2x State-of-the-art 2008 FClass 

(232 MW output each)

Gasifier Technology Shell Shell

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Feed Moisture Content, % 5 5

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H2S Separation Sulfinol-M Selexol 1st Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery Claus Plant with Tail Gas 

Treatment / Elemental Sulfur

Claus Plant with Tail Gas 

Treatment / Elemental Sulfur

Particulate Control Cyclone, Candle Filter, 

Scrubber, and AGR Absorber

Cyclone, Candle Filter, 

Scrubber, and AGR 

Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control

MNQC (LNB), N2 Dilution, 

Humidification and steam 

dilution

MNQC (LNB), N2 Dilution 

and Humidification

CO2 Separation N/A Selexol 2nd Stage

Overall Carbon Capture N/A 90.0%

CO2 Sequestration N/A Off-site Saline Formation
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Exhibit 3-11 Balance of plant assumptions

Parameters Values

Cooling system Recirculating Wet Cooling Tower

Fuel and Other storage

Coal 30 days

Slag 30 days

Sulfur 30 days

Sorbent 30 days

Plant Distribution Voltage

Motors below 1 hp 110/220 V

Motors between 1 hp and 250 hp 480 V

Motors between 250 hp and 5,000 

hp 4,160 V

Motors above 5,000 hp 13,800 V

Steam and Combustion Turbine 

Generators 24,000 V

Grid Interconnection Voltage 345 kV

Water and Waste Water

Makeup Water

The water supply is 50 percent from a local POTW and 

50 percent from groundwater, and is assumed to be in 

sufficient quantities to meet plant makeup requirements.

Makeup for potable, process, and de-ionized (DI) water is 

drawn from municipal sources

Process Wastewater

Water associated with gasification activity and storm water 

that contacts equipment surfaces is collected and treated 

for discharge through a permitted discharge.

Sanitary Waste Disposal

Design includes a packaged domestic sewage treatment 

plant with effluent discharged to the industrial wastewater 

treatment system. Sludge is hauled off site. Packaged 

plant was sized for 5.68 cubic meters per day 

(1,500 gallons per day)

Water Discharge

Most of the process wastewater is recycled to the cooling 

tower basin. Blowdown is treated for chloride and metals, 

and discharged.

3.2.4 Sparing Philosophy

The sparing philosophy for cases B1A and B1B is provided below. Dual trains are used to 

accommodate the size of commercial CTs. There is no redundancy other than normal sparing of 

rotating equipment. The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of coal drying and dry feed systems (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and barrier filter (2 x 50%) 

• Two trains of syngas clean-up process (2 x 50%)

• Two trains of Sulfinol-M acid gas removal in Case B1A and two-stage Selexol in Case 

B1B (2 x 50%)
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• Two CO2 compression systems (2 x 50%) in Case B1B

• One train of Claus-based sulfur recovery (1 x 100%) 

• Two CT/HRSG tandems (2 x 50%)

• One steam turbine (1 x 100%)

3.2.5 Case B1A - Performance Results

The plant produces a net output of 629 MWe at a net plant efficiency of 42.1 percent (HHV 

basis). Shell has reported expected efficiencies using bituminous coal of around 44-45 percent 

(HHV basis), although this value excluded the net power impact of coal drying. (48) Accounting 

for coal drying would reduce the efficiency by only about 0.5-1 percentage points so the 

efficiency results for the Shell case are still lower in this report than those reported by the 

vendor.

Overall performance for the entire plant is summarized in Exhibit 3-12; Exhibit 3-13 provides a 

detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 

79 percent of the total auxiliary load distributed between the main air compressor, oxygen 

compressor, nitrogen compressor, and ASU auxiliaries. The cooling water system, including the 

CWPs and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the 

BFW pumps account for an additional 4 percent. All other individual auxiliary loads are 3 

percent or less of the total.
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Exhibit 3-12 Case B1A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 273

Total Gross Power, MWe 737

Air Separation Unit Main Air Compressor, kWe 45,190

Oxygen Compressor, kWe 8,890

Nitrogen Compressors, kWe 29,850

CO2 Compression, kWe 0

Acid Gas Removal, kWe 620

Balance of Plant, kWe 23,550

Total Auxiliaries, MWe 108

Net Power, MWe 629

HHV Net Plant Efficiency (%) 42.1%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,546 (8,100)

HHV Cold Gas Efficiency, % 84.5%

HHV Combustion Turbine Efficiency, % 38.3%

LHV Net Plant Efficiency (%) 43.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,242 (7,812)

LHV Cold Gas Efficiency, % 82.8%

LHV Combustion Turbine Efficiency, % 40.5%

Steam Turbine Cycle Efficiency, % 44.8%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,037 (7,618)

Condenser Duty, GJ/hr (MMBtu/hr) 1,397 (1,324)

As-Received Coal Feed, kg/hr (lb/hr) 198,059 (436,646)

HHV Thermal Input, kWt 1,492,878

LHV Thermal Input, kWt 1,439,899

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.025 (6.6)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.020 (5.3)

O2:Coal 0.705
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Exhibit 3-13 Case B1A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 273

Total Gross Power, MWe 737

Auxiliary Load Summary

Coal Handling, kWe 440

Coal Milling, kWe 2,040

Sour Water Recycle Slurry Pump, kWe 0

Slag Handling, kWe 520

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 45,190

Oxygen Compressor, kWe 8,890

Nitrogen Compressors, kWe 29,850

Feedwater Pumps, kWe 4,500

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 680

CO2 Compression, kWe 0

Scrubber Pumps, kWe 770

Acid Gas Removal, kWe 620

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 3,400

Ground Water Pumps, kWe 380

Cooling Tower Fans, kWe 1,760

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 890

Miscellaneous Balance of PlantA, kWe 3,000

Transformer Losses, kWe 2,590

Total Auxiliaries, MWe 108

Net Power, MWe 629

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.2.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section

2.3. A summary of the plant air emissions for Case B1A is presented in Exhibit 3-14. All HCl is 

assumed to be removed and is, therefore, not reported.
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Exhibit 3-14 Case B1A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.002 (0.004) 68 (75) 0.013 (0.029)

NOx 0.025 (0.059) 957 (1,055) 0.185 (0.409)

Particulates 0.003 (0.0071) 115 (127) 0.022 (0.049)

Hg 1.87E-7 (4.34E-7) 0.007 (0.008) 1.36E-6 (3.00E-6)

CO2 85 (197) 3,188,643 (3,514,877) 617 (1,361)

CO2C - - 723 (1,595)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the Sulfinol-M 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 6 ppmv. This results in a concentration in the HRSG flue gas of 

less than 2 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is compressed and recycled back to the 

AGR to capture most of the remaining sulfur. The SO2 emissions in Exhibit 3-14 include both 

the stack emissions and the coal dryer emissions.

NOx emissions are limited by the use of nitrogen dilution, humidification, and steam dilution to 

15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with process 

condensate prior to the low-temperature AGR process and destroyed in the Claus plant burner. 

This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-15. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the slag and as CO2 in the stack gas and ASU vent gas.
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Exhibit 3-15 Case B1A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 126,252 (278,339) Stack Gas 124,177 (273,764)

Air (CO2) 508 (1,120) Coal Dryer Stack 1,863 (4,106)

CO2 Product 0 (0)

ASU Vent 89 (197)

Slag 631 (1,392)

Total 126,760 (279,459) Total 126,760 (279,459)

Exhibit 3-16 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur in the coal drying 

gas, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-16 Case B1A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 4,964 (10,944) Stack Gas 5 (11)

Coal Dryer Stack 0 (0)

CO2 Product 0 (0)

Elemental Sulfur 4,959 (10,933)

Total 4,964 (10,944) Total 4,964 (10,944)

Exhibit 3-17 shows the overall water balance for the plant.

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process, primarily as syngas condensate, and is re-used as internal 

recycle. The difference between demand and recycle is raw water withdrawal. Raw water 

withdrawal is defined as the water removed from the ground or diverted from a municipal source 

for use in the plant and was assumed to be provided 50 percent by a POTW and 50 percent from 

groundwater. Raw water withdrawal can be represented by the water metered from a raw water 

source and used in the plant processes for any and all purposes, such as cooling tower makeup, 

BFW makeup, quench system makeup, and slag handling makeup. The difference between 

water withdrawal and process water discharge is defined as water consumption and can be 

represented by the portion of the raw water withdrawn that is evaporated, transpired, 

incorporated into products or otherwise not returned to the water source from which it was 

withdrawn. Water consumption represents the net impact of the plant process on the water 

source balance.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

69

Exhibit 3-17 Case B1A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.43 (114) 0.17 (45) 0.26 (69) – 0.26 (69)

Slurry Water – – – – –

Quench/Wash – – – – –

Humidifier 1.38 (365) – 1.38 (365) – 1.38 (365)

SWS Blowdown – – – 0.00 (0.45) 0.00 (-0.45)

Condenser Makeup 1.07 (282) – 1.07 (282) – 1.07 (282)

 BFW Makeup 0.23 (62) – 0.23 (62) – 0.23 (62)

 Gasifier Steam 0.32 (84) – 0.32 (84) – 0.32 (84)

 Shift Steam – – – – –

 CT Steam Dilution 0.51 (135) – 0.51 (135) – 0.51 (135)

Cooling Tower 13.25 

(3,501) 0.25 (67) 13.00 (3,435) 2.98 (787) 10.02 (2,647)

 BFW Blowdown – 0.23 (62) -0.23 (-62) – -0.23 (-62)

 SWS Blowdown – 0.02 (4.50) -0.02 (-4.50) – -0.02 (-4.50)

Total 16.13 

(4,261) 0.42 (112) 15.71 (4,150) 2.98 (788) 12.73 (3,362)

3.2.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-18 through 

Exhibit 3-20:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-21. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-12) is calculated by multiplying the power out by a combined 

generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

70

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

71

Exhibit 3-18 Case B1A coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1A

SHELL GASIFIER

ASU, GASIFICATION, AND GAS COOLING

DWG. NO.

BB-HMB-CS-B1A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Nitrogen Compressor

Intercooled

Oxygen Compressor

Milled Coal

Slag

Removal

Slag

Gross Plant Power: 737 MWe

Auxiliary Load: 108 MWe

Net Plant Power: 629 MWe

Net Plant Efficiency, HHV: 42.1%

Net Plant Heat Rate: 8,100 Btu/kWh

Dry Coal

Coal

Feeding

Boost Compressor

Recycle

Compressor

280,565 W

220 T

225 P

51 H

337,302 W

393 T

625 P

147 H

To Claus Plant

9 10

1

3

4

7

6

11

2

1,168,307 W

59 T

15 P

13 H

48,319 W

70 T

16 P

16 H

937,042 W

90 T

56 P

14 H

130,495 W

50 T

182 P

3 H

6,236 W

90 T

125 P

11 H

325,738 W

90 T

125 P

11 H

325,738 W

241 T

940 P

41 H

54,557 W

376 T

785 P

84 H

436,646 W

59 T

15 P

408,345 W

60 T

840 P

43,732 W

2,600 T

615 P

1,124,342 W

1,974 T

615 P

750 H

787,039 W

375 T

585 P

140 H

280,565 W

810 T

235 P

199 H

1,012,980 W

389 T

384 P

88 H

5

42,132 W

650 T

740 P

1,309 H

Coal

Drying

Incinerator

Incinerator AirSyngas Slip Stream

11,218 W

112 T

530 P

26 H

53,179 W

59 T

15 P

13 H

92,698 W

12

8

1,067,536 W

199 T

384 P

40 H

337,302 W

375 T

585 P

140 H

Syngas 

Cooler

Duct Cooler

Steam 

Generation

Shell 

Gasifier

From HP 

Economizer 2

Air From GT 

Compressor

N2 to GT Combustor

From HP 

Economizer 2

To HP Economizer 1

1,124,342 W

600 T

595 P

221 H

Pre Particulat 

Cooler

Post 

Particulate 

Cooler

Cyclone

Candle 

Filter

To Superheater

From LP 

Economizer

To LP 

Evaporator

To Superheater

From HP 

Economizer 2

Raw Syngas

to Scrubber

1,124,342 W

1,650 T

605 P

620 H

1,167,264 W

100 T

190 P

18 H

13

Incinerator 

Exhaust

Steam

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Vent 

ASU

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

72

Exhibit 3-19 Case B1A syngas cleanup heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1A

SHELL GASIFIER

GAS CLEANUP SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

Sour 

Drum

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

COS

Hydrolysis

Reboiler

DWG. NO.

BB-HMB-CS-B1A-PG-2

PAGES

2 OF 3

Sour

Stripper

Clean 

Gas

Acid 

Gas

Syngas

Scrubber

Gross Plant Power: 737 MWe

Auxiliary Load: 108 MWe

Net Plant Power: 629 MWe

Net Plant Efficiency, HHV: 42.1%

Net Plant Heat Rate: 8,100 Btu/kWh

13

AGR- Sulfinol

15

16

20

21

22

787,039 W

375 T

585 P

140 H

23,692 W

100 T

800 P

5 H

782,178 W

201 T

580 P

75 H

782,178 W

351 T

565 P

128 H

790,887 W

94 T

535 P

19 H

Syngas

Coolers

From HP 

Economizer 2

746,680 W

112 T

530 P

26 H

1,962 W

142 T

65 P

76 H

30,253 W

450 T

59 P

433 H

32,989 W

112 T

530 P

6 H

Knock Out

Tailgas to AGR

To Superheater

782,178 W

350 T

575 P

128 H

767,195 W

94 T

540 P

19 H

6,561 W

119 T

57 P

45 H

Treated Syngas

14

Slip Stream 

to Coal Dryer

17

Humidification 18 19 Humidified Fuel Gas

8

Tailgas Recycle

Compressor

Hydrogenation

And Tail Gas 

Cooling

24,042 W

120 T

57 P

38 H

To Preheater and 

LP Evaporator

From Tail Gas 

Cooler and LP 

Economizer

To Fuel Gas 

Preheater

To Fuel Gas 

Preheater

992,575 W

195 T

580 P

159 H

992,575 W

150 T

1,205 P

113 H

To Water 

Treatment

Makeup Water

11,218 W

112 T

530 P

26 H

920,796 W

380 T

460 P

328 H

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas Scrubber 

and HP Economizer 1

920,796 W

321 T

465 P

305 H

From Gland Steam 

Condenser

To Syngas 

Cooling

110 T

COS Hydrolysis

Preheater

56,804 W

To Slag Quench

10,933 W

6,236 W

90 T

125 P

11 H

3

6,236 W

450 T

125 P

92 H

To 

Deaerator

From IP 

BFW

Fuel Gas 

Preheater

Claus Oxygen

Preheater

Oxygen

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

73

Exhibit 3-20 Case B1A combined cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1A

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B1A-PG-3

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,548,142 W

101 T

1 P

69 H

8,735,054 W

270 T

15 P

120 H

920,796 W

380 T

460 P

328 H

1,569,663 W

1,038 T

1,815 P

1,495 H

12,478 W

298 T

65 P

1,171 H

1,395,353 W

537 T

65 P

1,293 H

1,548,142 W

103 T

120 P

71 H

1,400 W

658 T

65 P

1,352 H

1,400 W

212 T

15 P

180 H

20

24

19

23

Hot Well

Condenser 140,852 W

59 T

15 P

27 H

8,841 W

698 T

501 P

1,348 H

9,537 W

658 T

65 P

1,352 H

782 W

1,038 T

1,815 P

1,495 H

1,314 W

537 T

65 P

1,293 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas Cooler

To Duct/Radiant 

Syngas/Pre 

Particulate Coolers 

and COS Preheater

From Duct/Radiant Syngas/Pre 

Particulate Coolers and COS 

Preheater

To ASU and Fuel 

Gas Preheater

Deaerator

From ASU and Fuel 

Gas Preheater

LP 

Evaporator

From Claus, Process Extraction, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat

8,735,054 W

1,088 T

15 P

340 H 22

To WWT

Condensate to Tail Gas 

Cooling

Process 

Extraction

235 T

274 T

1,712,806 W

274 T

45 P

242 H

1,604,593 W

279 T

2,251 P

247 H

8,564 W

274 T

79 P

242 H

19,460 W

274 T

79 P

242 H 35,526 W

276 T

615 P

244 H

571,152 W

351 T

2,251 P

319 H

305 T 585 T 636 T

34,923 W

585 T

2,001 P

585 H

636 T

1,190,740 W

585 T

2,001 P

585 H

1,446,064 W

698 T

501 P

1,348 H

571,152 W

585 T

2,001 P

585 H

1,012,980 W

385 T

389 P

87 H

21

Air Extraction

280,565 W

810 T

235 P

199 H

187,712 W

298 T

65 P

266 H

180 T

80,190 W

298 T

65 P

1,171 H

Steam to Gasifier 

and Combustion 

Turbine

109,842 W

688 T

745 P

1,327 H

Water Makeup

1,000 W

1,038 T

1,815 P

1,495 H 1,000 W

212 T

15 P

180 H

31,177 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

1,038 T

To Post 

Particulate 

and Syngas 

Coolers

From Post 

Particulate 

and Syngas 

Coolers

LP Extraction 

Spray #2

14,327 W

241 T

825 P

209 H

Process Extraction

40,813 W

537 T

65 P

1,293 H

Nitrogen Diluent

Fuel Gas Steam Diluent

67,710 W

475 T

460 P

1,233 H

IP to Claus

LP Pump

IP Pump

HP Pump

PLANT PERFORMANCE SUMMARY

Gross Plant Power: 737 MWe

Auxiliary Load: 108 MWe

Net Plant Power: 629 MWe

Net Plant Efficiency, HHV: 42.1%

Net Plant Heat Rate: 8,100 Btu/kWh

Condensate

Pumps

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

74

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

75

Exhibit 3-21 Case B1A overall energy balance (0°C [32°F] reference)

HHV Sensible + Latent Power Total

Heat In (GJ/hr)

Coal 5,374 (5,094) 4.5 (4.3) – 5,379 (5,098)

Air – 112.9 (107.0) – 112.9 (107.0)

Raw Water Makeup – 59.1 (56.0) – 59.1 (56.0)

Auxiliary Power – – 389 (369) 389 (369)

TOTAL 5,374 (5,094) 176.5 (167.3) 389 (369) 5,940 (5,630)

Heat Out (GJ/hr)

ASU Vent – 0.8 (0.8) – 0.8 (0.8)

Slag 20.7 (19.6) 33.5 (31.7) – 54.2 (51.4)

Stack Gas – 1,110 (1,052) – 1,110 (1,052)

Sulfur 46.0 (43.6) 0.6 (0.5) – 46.5 (44.1)

Motor Losses and 

Design Allowances

– – 51.8 (49.1) 51.8 (49.1)

Condenser – 1,397 (1,324) – 1,397 (1,324)

Non-Condenser Cooling 

Tower Loads

– 246 (233) – 246 (233)

CO2 – – – –

Blowdown – 22.9 (21.7) – 22.9 (21.7)

CO2 Capture Losses – – – –

Ambient LossesA – 113.9 (108.0) – 113.9 (108.0)

Power – – 2,653 (2,515) 2,653 (2,515)

TOTAL 66.7 (63.2) 2,925 (2,772) 2,705 (2,564) 5,696 (5,399)

Unaccounted EnergyB – 244 (231) – 244 (231)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of 

these losses include the combustor, reheater, superheater, and transformers.

BBy difference

3.2.6 Case B1A - Major Equipment List

Major equipment items for the Shell gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.2.7. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

76

Case B1A – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 160 tonne/hr (180 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 160 tonne (180 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 330 tonne/hr (360 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 730 tonne (800 ton) 3 0

Case B1A – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 70 tonne/hr (80 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 220 tonne/hr (240 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 440 tonne (480 ton) 1 0

4 Weigh Feeder Belt 110 tonne/hr (120 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 110 tonne/hr (120 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 220 tonne (240 ton) 2 0

Case B1A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor

1,165,000 liters 

(308,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,480 lpm @ 90 m H2O

(1,710 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 436,000 kg/hr (962,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

7,410 lpm @ 30 m H2O

(1,960 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

6,940 lpm @ 1,800 m H2O 

(1,830 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugalIP water: 2,470 lpm @ 220 m 

H2O (650 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded screw

28 m3/min @ 0.7 MPa

(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3min(1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 135 GJ/hr (128 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 48,500 lpm @ 20 m H2O(12,800 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

77

Equipment 

No. Description Type Design Condition Operating Qty. Spares

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

4,400 lpm @ 20 m H2O

(1,160 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,930 lpm @ 270 m H2O 

(780 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

1,780 lpm @ 50 m H2O

(470 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 852,000 liter (225,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 320 lpm (90 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B1A – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed

2,600 tonne/day, 4.2 MPa

(2,900 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 280,000 kg/hr (618,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 280,000 kg/hr (618,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 196,000 kg/hr (433,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 193,000 kg/hr (425,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

192,000 kg/hr, 35°C, 3.8 MPa

(423,000 lb/hr, 94°F, 545 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 131 GJ/hr (124 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 230,000 kg/hr, 161°C, 3.3 MPa

(506,000 lb/hr, 321°F, 480 psia) 2 0

10 Saturator Water 

Pump Centrifugal 3,600 lpm @ 13 m H2O(900 gpm @ 42 ft H2O) 2 2

11 Synthesis Gas 

Reheater Shell and tube 186,000 kg/hr (411,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

196,000 kg/hr 

(433,000 lb/hr) syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 4,000 m3/min @ 1.3 MPa(141,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,000 tonne/day (2,200 tpd) 

of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (35,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,000 m3/min (116,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

460 m3/min (16,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

78

Equipment 

No. Description Type Design Condition Operating Qty. Spares

18 Transport Nitrogen 

Boost Compressor

Centrifugal, singlestage

190 m3/min (7,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

19 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

70,000 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0

Case B1A – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 191,000 kg/hr (422,000 lb/hr),

35°C (94°F), 3.7 MPa (540 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 191,000 kg/hr (422,000 lb/hr),

35°C (94°F), 3.7 MPa (535 psia) 2 0

3 Sulfur Plant Claus type 131 tonne/day (144 tpd) 1 0

4 COS Hydrolysis 

Reactor Fixed bed, catalytic 195,000 kg/hr (430,000 lb/hr),177°C (350°F), 4.0 MPa (580 psia) 2 0

5 Acid Gas Removal 

Plant Sulfinol 197,000 kg/hr (435,000 lb/hr),34°C (94°F), 3.7 MPa (535 psia) 2 0

6 Hydrogenation 

Reactor Fixed bed, catalytic

15,000 kg/hr (33,000 lb/hr),

232°C (450°F), 0.4 MPa (58.9 

psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 12,000 kg/hr (26,000 lb/hr) each 1 0

Case B1A – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

Case B1A – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 391,593 kg/hr, 

12.4 MPa/559°C 

(863,314 lb/hr, 1,800 psig/1,038°F)

2 0

Case B1A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

287 MW

12.4 MPa/559°C/559°C 

(1,800 psig/ 1,038°F/1,038°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

320 MVA @ 0.9 p.f., 24 kV, 

60 Hz, 3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,540GJ/hr (1,460 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0
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Equipment 

No. Description Type Design Condition Operating Qty. Spares

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B1A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 342,000 lpm @ 30 m(90,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

1,900 GJ/hr (1,800 MMBtu/hr) heat duty

1 0

Case B1A – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 208,000 liters 

(55,000 gal) 2 0

2 Slag Crusher Roll 11 tonne/hr (12 tph) 2 0

3 Slag Depressurizer Lock Hopper 11 tonne/hr (12 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 125,000 liters (33,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 56,000 liters (15,000 gal) 2 0

6 Slag Conveyor Drag chain 11 tonne/hr (12 tph) 2 0

7 Slag Separation Screen Vibrating 11 tonne/hr (12 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 11 tonne/hr (12 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 178,000 liters (47,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 57,000 liters (15,000 gal) 2 0

12 Grey Water Pumps Centrifugal 200 lpm @ 430 m H2O

(50 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 90 tonne/hr (100 tph) 1 0

Case B1A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 290 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 23 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 3 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 

3-ph, 60 Hz 1 0
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Case B1A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.2.7 Case B1A - Cost Estimating

Costs Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-22 shows a 

detailed breakdown of the capital costs; Exhibit 3-23 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-24 shows the initial and annual O&M costs; and Exhibit 3-25 shows the COE 

breakdown. 

The estimated TPC of the Shell gasifier with no CO2 capture is $2,725/kW. Process contingency 

represents 2.8 percent of the TPC, and project contingency represents 13.8 percent. The COE is 

$107.0/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-22 Case B1A total plant cost details

Case: B1A – Shell IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,254 $0 $2,050 $0 $6,305 $630 $0 $1,387 $8,322 $13

1.2 Coal Stackout & Reclaim $5,498 $0 $1,314 $0 $6,812 $681 $0 $1,499 $8,992 $14

1.3 Coal Conveyors & Yd Crush $5,111 $0 $1,301 $0 $6,412 $641 $0 $1,411 $8,464 $13

1.4 Other Coal Handling $1,337 $0 $301 $0 $1,638 $164 $0 $360 $2,162 $3

1.9 Coal & Sorbent Hnd. Foundations $0 $2,841 $7,425 $0 $10,265 $1,027 $0 $2,258 $13,550 $22

Subtotal $16,200 $2,841 $12,391 $0 $31,432 $3,143 $0 $6,915 $41,491 $66

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $48,619 $2,932 $6,987 $0 $58,539 $5,854 $0 $12,878 $77,271 $123

2.2 Prepared Coal Storage & Feed $2,303 $553 $356 $0 $3,212 $321 $0 $707 $4,240 $7

2.3 Dry Coal Injection System $75,787 $873 $6,942 $0 $83,603 $8,360 $0 $18,393 $110,356 $175

2.4 Misc. Coal Prep & Feed $1,266 $925 $2,725 $0 $4,917 $492 $0 $1,082 $6,490 $10

2.9 Coal & Sorbent Feed Foundation $0 $4,645 $3,986 $0 $8,631 $863 $0 $1,899 $11,392 $18

Subtotal $127,976 $9,929 $20,996 $0 $158,901 $15,890 $0 $34,958 $209,749 $334

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,734 $6,444 $3,379 $0 $13,557 $1,356 $0 $2,983 $17,896 $28

3.2 Water Makeup & Pretreating $688 $71 $378 $0 $1,137 $114 $0 $375 $1,626 $3

3.3 Other Feedwater Subsystems $2,099 $694 $620 $0 $3,413 $341 $0 $751 $4,505 $7

3.4 Service Water Systems $402 $802 $2,765 $0 $3,969 $397 $0 $1,310 $5,676 $9

3.5 Other Boiler Plant Systems $2,168 $810 $1,994 $0 $4,971 $497 $0 $1,094 $6,562 $10

3.6 FO Supply Sys & Nat Gas $17,736 $712 $660 $0 $19,108 $1,911 $0 $4,204 $25,223 $40

3.7 Waste Treatment Equipment $931 $0 $576 $0 $1,507 $151 $0 $497 $2,155 $3

3.8 Misc. Power Plant Equipment $1,267 $169 $658 $0 $2,094 $209 $0 $691 $2,994 $5

Subtotal $29,025 $9,703 $11,029 $0 $49,757 $4,976 $0 $11,904 $66,637 $106

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $203,552 $0 $88,237 $0 $291,789 $29,179 $40,524 $55,413 $416,905 $663

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $177,729 $0 w/equip. $0 $177,729 $17,773 $0 $19,550 $215,052 $342

4.4 LT Heat Recovery & FG Saturation $18,617 $0 $7,073 $0 $25,691 $2,569 $0 $5,652 $33,911 $54

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,110 $449 $0 $1,559 $156 $0 $343 $2,058 $3

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,370 $5,588 $0 $14,957 $1,496 $0 $4,113 $20,567 $33

Subtotal $399,897 $10,480 $101,347 $0 $511,725 $51,172 $40,524 $85,072 $688,493 $1,095

5A Gas Cleanup & Piping

5A.1 Sulfinol System $45,130 $0 $38,032 $0 $83,162 $8,316 $0 $18,296 $109,774 $175

5A.2 Elemental Sulfur Plant $11,584 $2,258 $14,843 $0 $28,684 $2,868 $0 $6,311 $37,863 $60

5A.3 Mercury Removal $1,400 $0 $1,058 $0 $2,458 $246 $123 $565 $3,392 $5

5A.4 COS Hydrolysis $3,475 $0 $4,507 $0 $7,981 $798 $0 $1,756 $10,535 $17

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case: B1A – Shell IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.6 Blowback Gas Systems $1,945 $327 $183 $0 $2,455 $245 $0 $540 $3,240 $5

5A.7 Fuel Gas Piping $0 $979 $640 $0 $1,619 $162 $0 $356 $2,137 $3

5A.9 HGCU Foundations $0 $886 $597 $0 $1,483 $148 $0 $489 $2,120 $3

Subtotal $63,533 $4,449 $59,860 $0 $127,842 $12,784 $123 $28,313 $169,062 $269

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,201 $0 $7,506 $0 $111,707 $11,171 $5,585 $12,846 $141,309 $225

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $5

Subtotal $104,201 $923 $8,575 $0 $113,699 $11,370 $5,585 $13,504 $144,158 $229

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,100 $0 $6,022 $0 $37,122 $3,712 $0 $4,083 $44,918 $71

7.3 Ductwork $0 $2,085 $1,461 $0 $3,546 $355 $0 $780 $4,681 $7

7.4 Stack $4,023 $0 $1,501 $0 $5,524 $552 $0 $608 $6,684 $11

7.9 HRSG, Duct & Stack Foundations $0 $766 $769 $0 $1,535 $153 $0 $506 $2,195 $3

Subtotal $35,123 $2,851 $9,753 $0 $47,727 $4,773 $0 $5,978 $58,477 $93

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,584 $0 $5,922 $0 $44,506 $4,451 $0 $4,896 $53,852 $86

8.2 Turbine Plant Auxiliaries $241 $0 $549 $0 $791 $79 $0 $87 $957 $2

8.3 Condenser & Auxiliaries $3,110 $0 $1,755 $0 $4,865 $486 $0 $535 $5,886 $9

8.4 Steam Piping $16,344 $0 $7,088 $0 $23,432 $2,343 $0 $6,444 $32,218 $51

8.9 TG Foundations $0 $1,137 $2,009 $0 $3,146 $315 $0 $1,038 $4,499 $7

Subtotal $58,279 $1,137 $17,322 $0 $76,739 $7,674 $0 $13,000 $97,412 $155

9 Cooling Water System

9.1 Cooling Towers $3,610 $0 $1,090 $0 $4,700 $470 $0 $776 $5,946 $9

9.2 Circulating Water Pumps $1,751 $0 $120 $0 $1,871 $187 $0 $309 $2,367 $4

9.3 Circ. Water System Auxiliaries $157 $0 $22 $0 $179 $18 $0 $30 $227 $0

9.4 Circ. Water Piping $0 $6,965 $1,687 $0 $8,652 $865 $0 $1,903 $11,421 $18

9.5 Make-up Water System $395 $0 $542 $0 $937 $94 $0 $206 $1,237 $2

9.6 Component Cooling Water Sys $796 $952 $654 $0 $2,403 $240 $0 $529 $3,171 $5

9.9 Circ. Water System Foundations $0 $2,272 $4,038 $0 $6,310 $631 $0 $2,082 $9,024 $14

Subtotal $6,709 $10,190 $8,153 $0 $25,052 $2,505 $0 $5,834 $33,392 $53

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $18,726 $0 $9,172 $0 $27,898 $2,790 $0 $3,069 $33,756 $54

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $635 $0 $686 $0 $1,321 $132 $0 $218 $1,671 $3

10.7 Ash Transport & Feed Equipment $874 $0 $204 $0 $1,078 $108 $0 $178 $1,364 $2

10.8 Misc. Ash Handling Equipment $1,315 $1,612 $478 $0 $3,405 $341 $0 $562 $4,307 $7

10.9 Ash/Spent Sorbent Foundation $0 $53 $70 $0 $123 $12 $0 $41 $176 $0

Subtotal $21,550 $1,665 $10,610 $0 $33,826 $3,383 $0 $4,067 $41,275 $66

11 Accessory Electric Plant

11.1 Generator Equipment $1,155 $0 $1,125 $0 $2,280 $228 $0 $251 $2,758 $4

11.2 Station Service Equipment $4,293 $0 $395 $0 $4,687 $469 $0 $516 $5,672 $9
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Case: B1A – Shell IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 629 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.3 Switchgear & Motor Control $7,923 $0 $1,473 $0 $9,396 $940 $0 $1,550 $11,885 $19

11.4 Conduit & Cable Tray $0 $4,026 $12,409 $0 $16,435 $1,643 $0 $4,520 $22,598 $36

11.5 Wire & Cable $0 $7,762 $4,722 $0 $12,484 $1,248 $0 $3,433 $17,165 $27

11.6 Protective Equipment $0 $797 $2,958 $0 $3,755 $375 $0 $620 $4,750 $8

11.7 Standby Equipment $275 $0 $274 $0 $548 $55 $0 $90 $693 $1

11.8 Main Power Transformers $17,455 $0 $173 $0 $17,628 $1,763 $0 $2,909 $22,299 $35

11.9 Electrical Foundations $0 $181 $493 $0 $674 $67 $0 $222 $963 $2

Subtotal $31,100 $12,765 $24,020 $0 $67,885 $6,789 $0 $14,110 $88,784 $141

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,195 $0 $814 $0 $2,010 $201 $100 $347 $2,658 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $275 $0 $180 $0 $454 $45 $23 $105 $627 $1

12.7 Computer & Accessories $6,376 $0 $208 $0 $6,585 $658 $329 $757 $8,330 $13

12.8 Instrument Wiring & Tubing $0 $2,455 $4,646 $0 $7,101 $710 $355 $2,042 $10,208 $16

12.9 Other I & C Equipment $4,262 $0 $2,112 $0 $6,374 $637 $319 $1,100 $8,430 $13

Subtotal $12,109 $2,455 $7,961 $0 $22,524 $2,252 $1,126 $4,350 $30,252 $48

13 Improvements to Site

13.1 Site Preparation $0 $117 $2,670 $0 $2,788 $279 $0 $920 $3,986 $6

13.2 Site Improvements $0 $2,089 $2,953 $0 $5,042 $504 $0 $1,664 $7,210 $11

13.3 Site Facilities $3,743 $0 $4,202 $0 $7,945 $794 $0 $2,622 $11,361 $18

Subtotal $3,743 $2,206 $9,825 $0 $15,774 $1,577 $0 $5,206 $22,557 $36

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,909 $4,142 $0 $7,051 $705 $0 $1,163 $8,919 $14

14.3 Administration Building $0 $1,008 $731 $0 $1,739 $174 $0 $287 $2,199 $3

14.4 Circulation Water Pumphouse $0 $199 $105 $0 $304 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $565 $551 $0 $1,117 $112 $0 $184 $1,413 $2

14.6 Machine Shop $0 $516 $353 $0 $869 $87 $0 $143 $1,099 $2

14.7 Warehouse $0 $833 $537 $0 $1,370 $137 $0 $226 $1,733 $3

14.8 Other Buildings & Structures $0 $499 $388 $0 $887 $89 $0 $195 $1,171 $2

14.9 Waste Treating Building & Str. $0 $1,115 $2,130 $0 $3,245 $325 $0 $714 $4,283 $7

Subtotal $0 $7,961 $9,116 $0 $17,077 $1,708 $0 $3,072 $21,857 $35

Total $909,446 $79,555 $310,959 $0 $1,299,960 $129,996 $47,358 $236,282 $1,713,596 $2,725
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Exhibit 3-23 Case B1A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $15,220 $24

1 Month Maintenance Materials $3,484 $6

1 Month Non-fuel Consumables $371 $1

1 Month Waste Disposal $405 $1

25% of 1 Months Fuel Cost at 100% CF $2,731 $4

2% of TPC $34,272 $54

Total $56,482 $90

Inventory Capital

60-day supply of fuel and consumables at 100% CF $22,284 $35

0.5% of TPC (spare parts) $8,568 $14

Total $30,852 $49

Other Costs

Initial Cost for Catalyst and Chemicals $2,032 $3

Land $900 $1

Other Owner's Costs $257,039 $409

Financing Costs $46,267 $74

Total Overnight Costs (TOC) $2,107,169 $3,351

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,402,172 $3,820
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-24 Case B1A initial and annual operating and maintenance costs

Case: B1A – Shell IGCC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 629 Heat Rate-net (Btu/kWh): 8,100 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 9.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 15.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $6,781,554 $10.783

Maintenance Labor: $17,570,241 $27.938

Administrative & Support Labor: $6,087,949 $9.680

Property Taxes and Insurance: $34,271,927 $54.495

Total: $64,711,671 $102.897

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $33,446,804 $7.58890

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 2,988 $1.67 $0 $1,460,528 $0.33139

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 17,801 $0.27 $0 $1,392,224 $0.31589

Carbon (Mercury Removal) (lb): 116,013 199 $5.50 $638,069 $319,034 $0.07239

COS Catalyst (m3): 262 0.18 $3,751.70 $982,135 $196,427 $0.04457

Sulfinol Solution (gal): 26,146 18 $15.73 $411,337 $81,630 $0.01852

Claus Catalyst (ft3): w/equip. 1.82 $203.15 $0 $108,246 $0.02456

Subtotal: $2,031,540 $3,558,089 $0.80731

Waste Disposal

Spent Mercury Catalyst (lb.): 0 199 $0.65 $0 $37,710 $0.00856

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 525 $25.11 $0 $3,847,802 $0.87305

 Subtotal: $0 $3,885,512 $0.88160

By-Products

Sulfur (tons): 0 131 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $2,031,540 $40,890,405 $9.27782

Fuel Cost

Illinois Number 6 (ton): 0 5,240 $68.54 $0 $104,866,703 $23.79370

Total: $0 $104,866,703 $23.79370

Exhibit 3-25 Case B1A COE breakdown

Component Value, $/MWh Percentage

Capital 59.3 55%

Fixed 14.7 14%

Variable 9.3 9%

Fuel 23.8 22%

Total (Excluding T&S) 107.0 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 107.0 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.2.8 Case B1B - Shell IGCC Power Plant with CO2 Capture

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case B1A, namely two Shell gasifier trains, two state-of-the-art 2008 F-class 

turbines, two HRSGs, and one steam turbine. The gross power output is constrained by the 

capacity of the two CTs, and since the CO2 capture and compression process increases the 

auxiliary load on the plant, the net output is significantly reduced relative to Case B1A (497 MW 

versus 629 MW).

The process description for Case B1B is similar to Case B1A with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case B1B are shown in Exhibit 3-26

and Exhibit 3-27, respectively. Instead of repeating the entire process description, only 

differences from Case B1A are reported here.

3.2.8.1 Coal Preparation and Feed Systems

No differences from Case B1A.

3.2.8.2 Gasification

The gasification process is the same as Case B1A with the exception that total coal feed to the 

two gasifiers is 5,065 tonnes/day (5,583 tpd) (stream 9) and the ASU provides 3,852 tonnes/day 

(4,246 tpd) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

3.2.8.3 Raw Gas Cooling/Particulate Removal

After the raw syngas is cooled to approximately 1,093°C (2,000°F) by the syngas quench 

recycle, syngas is further cooled to 899°C (1,650°F) by raising HP steam at 13.8 MPa (2,000 

psia). A direct contact water quench follows to cool the raw syngas from 899°C (1,650°F) to 

399°C (750°F) while providing a portion of the water required for SGS. The syngas is then 

cooled to 316°C (600°F) by raising steam, which is used in the SGS unit. After particulate 

filtration, the syngas is cooled to 232°C (450°F) by raising IP steam at 0.4 MPa (65 psia) before 

proceeding to the scrubber.

3.2.8.4 Syngas Scrubber/Sour Water Stripper

Syngas exits the scrubber at 191°C (376°F).

3.2.8.5 Sour Gas Shift

The SGS process was described in Section 3.1.3. In Case B1B the syngas after the scrubber is 

reheated to 197°C (386°F) and then steam (stream 14) is added to adjust the H2O:CO molar ratio 

to approximately 1.8:1 prior to the first SGS reactor. The hot syngas exiting the first stage of 

SGS is used to preheat water used to humidify clean syngas prior to entering the CT. One more 

stage of SGS (for a total of two) results in 97.8 percent overall conversion of the CO to CO2. 

The warm syngas from the second stage of SGS is cooled to 248°C (478°F) by preheating the 

syngas prior to the first stage of SGS. The SGS catalyst also serves to hydrolyze COS thus 

eliminating the need for a separate COS hydrolysis reactor. Following the second stage of SGS, 

the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

3.2.8.6 Mercury Removal and AGR

Mercury removal is the same as in Case B1A.
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The AGR process in Case B1B is a two-stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption. The process results in three product streams, 

the clean syngas (stream 18), a CO2-rich stream and an acid gas feed to the Claus plant (stream 

22). The acid gas contains 34 percent H2S and 51 percent CO2 with the balance primarily H2. 

The CO2-rich stream is discussed further in the CO2 compression section. 

3.2.8.7 CO2 Compression and Dehydration

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

1.0 MPa (149.5 psia) to an SC condition at 15.3 MPa (2215 psia) using a multiple-stage, 

intercooled compressor. During compression, the CO2 stream is dehydrated to a dew point 

of -40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 21) is transported to the plant fence line and is 

sequestration ready. CO2 T&S costs were estimated using the methodology described in Section 

2.6.

3.2.8.8 Claus Unit

The Claus plant is the same as Case B1A with the following exceptions:

• 5,277 kg/hr (11,634 lb/hr) of sulfur (stream 23) are produced

• The waste heat boiler generates 13,697 kg/hr (30,197 lb/hr) of 3.0 MPa (430 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header.

3.2.8.9 Power Block

Clean syngas from the AGR plant is combined with a small amount of clean gas from the CO2

compression process (stream 18) and partially humidified because the nitrogen available from 

the ASU is insufficient to provide adequate dilution. The moisturized syngas is reheated to 

193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then enters the CT burner. 

The exhaust gas (stream 27) exits the CT at 562°C (1,043°F) and enters the HRSG where 

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 28) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1,800 psig/993°F/993°F) 

steam cycle.

3.2.8.10 Air Separation Unit (ASU)

The same elevated pressure ASU is used as in Case B1A and produces 3,852 tonnes/day (4,246 

tpd) of 95 mol% oxygen and 12,290 tonnes/day (13,547 tpd) of nitrogen. There is no integration 

between the ASU and the CT in the CO2 capture case.

3.2.8.11 Balance of Plant

Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.12.
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Exhibit 3-26 Case B1B block flow diagram, Shell IGCC with CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

SYNGAS

QUENCH AND

COOLING

WATER-GAS

SHIFT REACTORS

& GAS COOLING

WATER

SCRUBBER

ELEVATED

PRESSURE

ASU

SHELL GASIFIER

MERCURY

REMOVAL

DUALSTAGE

SELEXOL

UNIT

CLAUS

PLANT

SYNGAS

REHEAT

HRSG

2X STATE-OF-THEART F-CLASS

GAS TURBINES

1

AIR TO ASU

2 3

VENT

GAS

5

10 11

GASIFIER

OXIDANT

DRY

COAL SLAG

16 17

22

23

4

26

TURBINE COOLING AIR

27

AMBIENT AIR

FLUE GAS STACK GAS

HYDROGENATION

REACTOR AND GAS

COOLING

24

CLEAN

GAS

NITROGEN DILUENT

SULFUR

PRODUCT

SYNGAS

COAL

DRYER

DRYING

GAS

PREP

9

WET

COAL

18

8

6

13

12

AIR

SYNGAS

STEAM

CO2

COMPRESSOR 21

14

15

CO2

PRODUCT

20

SHIFT

STEAM

7 TRANSPORT

NITROGEN

28

CLAUS

PLANT

OXIDANT

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

29

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

SYNGAS

QUENCH

RECYCLE

25

SOUR

WATER

STRIPPER

WATER RECYCLE

TO PROCESS

DEMAND

SYNGAS

HUMIDIFICATION

19
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Exhibit 3-27 Case B1B stream table, Shell IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0230 0.0318 0.0023 0.0318 0.0000 0.0023 0.0096 0.0000 0.0000 0.0000 0.0085 0.0061 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0000 0.0000 0.0005 0.0004 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0130 0.0000 0.0000 0.0000 0.5187 0.3712 0.0000

CO2 0.0003 0.0079 0.0000 0.0000 0.0000 0.0000 0.0000 0.0455 0.0000 0.0000 0.0000 0.0126 0.0090 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0004 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.8727 0.0000 0.8090 0.0000 0.2691 0.1926 0.0000

H2O 0.0099 0.1984 0.0000 0.0003 0.0000 1.0000 0.0004 0.0001 0.0000 0.0935 0.0000 0.1278 0.3758 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0030 0.0000 0.0008 0.0006 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0052 0.0000

N2 0.7732 0.5759 0.0178 0.9919 0.0178 0.0000 0.9919 0.0585 0.0000 0.0163 0.0000 0.0507 0.0363 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0033 0.0024 0.0000

O2 0.2074 0.1948 0.9504 0.0054 0.9504 0.0000 0.0054 0.0000 0.0000 0.0782 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 24,277 1,004 102 17,310 4,886 1,130 940 308 0 5,809 0 26,493 29,249 11,003

V-L Flowrate (kg/hr) 700,548 27,328 3,289 485,713 157,225 20,363 26,368 1,900 0 37,081 0 531,672 569,894 198,214

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 211,040 160,281 21,137 0 0 0

Temperature (°C) 15 20 32 93 32 343 32 35 15 16 1,427 1,082 232 288

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 5.62 3.59 0.10 5.79 4.24 4.24 4.03 5.52

Steam Table Enthalpy (kJ/kg) A 30.23 36.90 26.67 92.51 26.67 3,063.97 20.78 163.14 --- --- --- 2,047.11 1,220.20 2,918.18

AspenPlus Enthalpy (kJ/kg)B -97.58 -2,197.43 4.13 63.47 4.13 -12,907.38 -8.79 -3,104.81 -2,116.95 -768.33 2,165.43 -2,946.51 -6,659.43 -13,053.16

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 20.1 62.8 8.5 --- 16.5 --- 7.5 19.1 25.6

V-L Molecular Weight 28.857 27.206 32.181 28.060 32.181 18.015 28.060 6.159 --- 6.383 --- 20.069 19.484 18.015

V-L Flowrate (lbmole/hr) 53,521 2,215 225 38,162 10,771 2,492 2,072 680 0 12,807 0 58,407 64,482 24,256

V-L Flowrate (lb/hr) 1,544,445 60,248 7,250 1,070,814 346,622 44,894 58,132 4,188 0 81,749 0 1,172,137 1,256,401 436,986

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 465,264 353,359 46,599 0 0 0

Temperature (°F) 59 68 90 199 90 650 90 94 59 60 2,600 1,980 450 550

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 815.0 520.0 14.7 840.0 615.0 615.0 585.0 800.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 1,317.3 8.9 70.1 --- --- --- 880.1 524.6 1,254.6

AspenPlus Enthalpy (Btu/lb)B -42.0 -944.7 1.8 27.3 1.8 -5,549.2 -3.8 -1,334.8 -910.1 -330.3 931.0 -1,266.8 -2,863.0 -5,611.9

Density (lb/ft3) 0.076 0.097 0.687 1.521 0.687 1.257 3.918 0.531 --- 1.029 --- 0.468 1.190 1.597

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-27 Case B1B stream table, Shell IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25 26 27 28 29

V-L Mole Fraction

Ar 0.0047 0.0062 0.0062 0.0096 0.0086 0.0086 0.0002 0.0017 0.0000 0.0065 0.0102 0.0092 0.0088 0.0088 0.0000

CH4 0.0003 0.0004 0.0004 0.0006 0.0005 0.0005 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.2873 0.0084 0.0084 0.0130 0.0116 0.0116 0.0002 0.0025 0.0000 0.1143 0.0060 0.0000 0.0000 0.0000 0.0000

CO2 0.0070 0.3776 0.3810 0.0455 0.0407 0.0407 0.9944 0.5141 0.0000 0.2866 0.6257 0.0003 0.0080 0.0080 0.0000

COS 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.1491 0.5633 0.5593 0.8727 0.7819 0.7819 0.0050 0.1068 0.0000 0.0659 0.2694 0.0000 0.0000 0.0000 0.0000

H2O 0.5172 0.0016 0.0016 0.0001 0.1041 0.1041 0.0000 0.0300 0.0000 0.4715 0.0017 0.0099 0.1374 0.1374 1.0000

HCl 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0040 0.0057 0.0057 0.0000 0.0000 0.0000 0.0000 0.3398 0.0000 0.0014 0.0057 0.0000 0.0000 0.0000 0.0000

N2 0.0281 0.0368 0.0374 0.0585 0.0524 0.0524 0.0002 0.0047 0.0000 0.0516 0.0813 0.7732 0.7397 0.7397 0.0000

NH3 0.0019 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1060 0.1060 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 37,783 28,837 29,237 18,312 20,438 20,438 10,099 488 0 630 400 110,253 139,892 139,892 28,855

V-L Flowrate (kg/hr) 723,426 562,223 574,690 112,786 151,092 151,092 442,270 17,202 0 16,585 12,466 3,181,557 3,818,362 3,818,362 519,836

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 0 5,277 0 0 0 0 0 0

Temperature (°C) 217 35 35 35 137 193 51 48 178 232 38 15 562 132 534

Pressure (MPa, abs) 3.96 3.62 3.59 3.59 3.21 3.17 15.27 0.16 0.12 0.08 5.51 0.10 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 1,541.73 45.33 44.53 163.14 1,181.24 1,416.72 -161.70 85.01 --- 1,114.50 8.30 30.23 866.14 371.29 3,432.00

AspenPlus Enthalpy (kJ/kg)B -8,063.86 -7,695.78 -7,701.53 -3,104.81 -5,307.37 -5,071.89 -9,118.58 -6,131.59 142.40 -8,838.52 -7,960.81 -97.58 -720.70 -1,215.55 -12,538.31

Density (kg/m3) 19.5 28.1 28.1 8.5 6.9 6.0 639.8 2.2 5,279.4 0.5 74.4 1.2 0.4 0.8 36.8

V-L Molecular Weight 19.147 19.496 19.656 6.159 7.393 7.393 43.792 35.245 --- 26.336 31.160 28.857 27.295 27.295 18.015

V-L Flowrate (lbmole/hr) 83,298 63,576 64,458 40,371 45,059 45,059 22,265 1,076 0 1,388 882 243,066 308,408 308,408 63,615

V-L Flowrate (lb/hr) 1,594,881 1,239,491 1,266,974 248,650 333,100 333,100 975,038 37,925 0 36,563 27,484 7,014,133 8,418,047 8,418,047 1,146,042

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 0 11,634 0 0 0 0 0 0

Temperature (°F) 422 95 94 94 278 380 124 119 352 450 100 59 1,043 270 993

Pressure (psia) 575.0 525.0 520.0 520.0 465.0 460.0 2,214.7 23.7 17.3 12.3 799.5 14.7 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 662.8 19.5 19.1 70.1 507.8 609.1 -69.5 36.5 --- 479.1 3.6 13.0 372.4 159.6 1,475.5

AspenPlus Enthalpy (Btu/lb)B -3,466.8 -3,308.6 -3,311.1 -1,334.8 -2,281.8 -2,180.5 -3,920.3 -2,636.1 61.2 -3,799.9 -3,422.5 -42.0 -309.8 -522.6 -5,390.5

Density (lb/ft3) 1.218 1.753 1.753 0.531 0.431 0.374 39.942 0.135 329.584 0.033 4.646 0.076 0.026 0.053 2.295

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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3.2.9 Case B1B - Performance Results

The Case B1B modeling assumptions were presented previously in Section 3.2.3.

The plant produces a net output of 497 MWe at a net plant efficiency of 31.2 percent (HHV 

basis). Overall performance for the plant is summarized in Exhibit 3-28; Exhibit 3-29 provides a 

detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 

58 percent of the auxiliary load between the main air compressor, nitrogen compressor, oxygen 

compressor, and ASU auxiliaries. The two-stage Selexol process and CO2 compression account 

for an additional 28 percent of the auxiliary power load. The BFW and CWS (CWPs and 

cooling tower fan) compose approximately 4 percent of the load, leaving 10 percent of the 

auxiliary load for all other systems.

Exhibit 3-28 Case B1B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 209

Total Gross Power, MWe 673

Air Separation Unit Main Air Compressor, kWe 59,740

Oxygen Compressor, kWe 9,460

Nitrogen Compressors, kWe 32,910

CO2 Compression, kWe 30,210

Acid Gas Removal, kWe 18,650

Balance of Plant, kWe 25,690

Total Auxiliaries, MWe 177

Net Power, MWe 497

HHV Net Plant Efficiency (%) 31.2%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,528 (10,927)

HHV Cold Gas Efficiency, % 84.5%

HHV Combustion Turbine Efficiency, % 35.9%

LHV Net Plant Efficiency (%) 32.4%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,119 (10,539)

LHV Cold Gas Efficiency, % 82.9%

LHV Combustion Turbine Efficiency, % 42.3%

Steam Turbine Cycle Efficiency, % 39.0%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,238 (8,756)

Condenser Duty, GJ/hr (MMBtu/hr) 1,335 (1,265)

As-Received Coal Feed, kg/hr (lb/hr) 211,040 (465,264)

HHV Thermal Input, kWt 1,590,722

LHV Thermal Input, kWt 1,534,271

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.043 (11.4)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.035 (9.3)

O2:Coal 0.704
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Exhibit 3-29 Case B1B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 209

Total Gross Power, MWe 673

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,170

Sour Water Recycle Slurry Pump, kWe 0

Slag Handling, kWe 550

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 59,740

Oxygen Compressor, kWe 9,460

Nitrogen Compressors, kWe 32,910

Feedwater Pumps, kWe 3,500

Quench Water Pump, kWe 610

Syngas Recycle Compressor, kWe 790

CO2 Compression, kWe 30,210

Scrubber Pumps, kWe 360

Acid Gas Removal, kWe 18,650

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 280

Circulating Water Pumps, kWe 4,380

Ground Water Pumps, kWe 510

Cooling Tower Fans, kWe 2,270

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,830

Miscellaneous Balance of PlantA, kWe 3,000

Transformer Losses, kWe 2,630

Total Auxiliaries, MWe 177

Net Power, MWe 497

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.2.9.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.4. A summary of the plant air emissions for Case B1B is presented in Exhibit 3-30. 

All HCl is assumed to be removed and is, therefore, not reported.
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Exhibit 3-30 Case B1B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.001 (0.002) 37 (40) 0.008 (0.017)

NOx 0.021 (0.049) 847 (934) 0.180 (0.396)

Particulates 0.003 (0.0071) 123 (135) 0.026 (0.057)

Hg 1.60E-7 (3.72E-7) 0.006 (0.007) 1.36E-6 (3.00E-6)

CO2 9 (20) 344,507 (379,754) 73 (161)

CO2C - - 99 (218)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the two-stage 

Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to 

a greater extent than required in the environmental targets of Section 2.3. The clean syngas 

exiting the AGR process has a sulfur concentration of approximately 4 ppmv. This results in a 

concentration in the HRSG flue gas of less than 1 ppmv. The H2S-rich regeneration gas from the 

AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

compressed and recycled back to the AGR where most of the remaining sulfur is removed.

NOx emissions are limited by the use of nitrogen dilution and humidification to 15 ppmvd (as 

NO2 @ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the 

low-temperature AGR process and subsequently destroyed in the Claus plant burner. This helps 

lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of mercury is captured from the syngas by dual activated carbon beds.

Ninety two percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall carbon

removal is 90.0 percent.

The carbon balance for the plant is shown in Exhibit 3-31. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as unburned carbon 

in the slag and as CO2 in the stack gas, coal dryer vent gas, ASU vent gas, and the captured CO2

product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack 

gas relative to the total carbon in less carbon contained in the slag, represented by the following 

fraction: 

CCCCCCCCCC SS SSSS

(TT TT CCCCCCCCCC ) − (CCCCCCCCCC SS SS) = �1 − � 29,578

297,754 − 1,483� ∗� 100 = 90.0%
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-31 Case B1B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 134,527 (296,581) Stack Gas 13,416 (29,578)

Air (CO2) 532 (1,173) Coal Dryer Stack 223 (491)

CO2 Product 120,652 (265,992)

ASU Vent 95 (210)

Slag 673 (1,483)

Total 135,059 (297,754) Total 135,059 (297,754)

Exhibit 3-32 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur from the tail gas unit that is vented through the coal dryer. Sulfur in the 

slag is considered negligible.

Exhibit 3-32 Case B1B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,290 (11,661) Stack Gas 3 (6)

Coal Dryer Stack 0 (0)

CO2 Product 10 (22)

Elemental Sulfur 5,277 (11,634)

Total 5,290 (11,661) Total 5,290 (11,661)

Exhibit 3-33 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for Case B1A.
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Exhibit 3-33 Case B1B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.46 (121) 0.46 (121) – – –

Slurry Water – – – – –

Quench/Wash 3.17 (836) 2.22 (587) 0.94 (250) – 0.94 (250)

Humidifier 0.67 (177) 0.67 (177) – – –

SWS Blowdown – – – 0.03 (7.08) -0.03 (-7.08)

Condenser Makeup 3.83 (1,012) – 3.83 (1,012) – 3.83 (1,012)

 BFW Makeup 0.18 (48) – 0.18 (48) – 0.18 (48)

 Gasifier Steam 0.34 (90) – 0.34 (90) – 0.34 (90)

 Shift Steam 3.31 (874) – 3.31 (874) – 3.31 (874)

 CT Steam Dilution – – – – –

Cooling Tower 17.07 

(4,510) 0.45 (119) 16.62 (4,391) 3.84 (1,014) 12.78 (3,377)

 BFW Blowdown – 0.18 (48) -0.18 (-48) – -0.18 (-48)

 SWS Blowdown – 0.27 (70.80) -0.27 (-

70.80) – -0.27 (-70.80)

Total 25.20 

(6,657) 3.80 (1,004) 21.40 (5,652) 3.87 (1,021) 17.53 (4,631)

3.2.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-34 through 

Exhibit 3-36:

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-37. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-28) is calculated by multiplying the power out by a combined 

generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

96

Exhibit 3-34 Case B1B coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1B

SHELL GASIFIER

ASU, GASIFICATION, AND GAS COOLING

DWG. NO.

BB-HMB-CS-B1B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

1 OF 3

Ambient Air

Intercooled

Air Compressor

Elevated

Pressure

ASU

Intercooled

Nitrogen Compressor

Intercooled

Oxygen Compressor

Milled Coal

Water

Steam

Slag

Removal

Slag

Gross Plant Power: 673 MWe

Auxiliary Load: 177 MWe

Net Plant Power: 497 MWe

Net Plant Efficiency, HHV: 31.2%

Net Plant Heat Rate: 10,927 Btu/kWh

Dry Coal

Coal

Feeding

Steam

Candle 

Cyclone Filter

N2 to GT Combustor

Boost Compressor

Recycle

Compressor

Raw Syngas

to Scrubber

333,980 W

520 T

625 P

552 H

To Claus Plant

9 10

1

3

7

6

11

13

2

1,544,445 W

59 T

15 P

13 H

60,248 W

68 T

16 P

16 H

989,843 W

90 T

56 P

14 H 139,103 W

50 T

182 P

3 H

7,250 W

90 T

125 P

11 H

346,622 W

90 T

125 P

11 H

346,622 W

241 T

940 P

58,132 W 41 H

387 T

815 P

87 H

465,264 W

59 T

15 P

435,108 W

60 T

840 P

46,599 W

2,600 T

615 P

1,172,137 W

1,980 T

615 P

878 H

1,256,401 W

450 T

585 P

523 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

687,451 W

385 T

384 P

87 H

5

44,894 W

650 T

740 P

1,309 H

Coal

Drying

Incinerator

Incinerator Air Syngas Slip Stream

Flue Gas/

Combustion

Products

4,188 W

94 T

520 P

70 H

63,439 W

59 T

15 P

13 H

97,783 W

8

1,128,946 W

199 T

384 P

40 H

333,980 W

450 T

585 P

523 H

Syngas

Quench

Cooler

Quench Water

418,244 W

420 T

1,200 P

388 H

To Reheater, Shift Steam, 

and gasifier

To LP 

Evaporator

From IP BFW

From LP 

Economizer

N2 Compressor

12

1,590,381 W

600 T

595 P

585 H

1,590,381 W

750 T

605 P

647 H

1,543,066 W

100 T

190 P

18 H

383,362 W

385 T

469 P

87 H

Syngas 

Cooler

Duct Cooler

Steam 

Generation

Shell 

Gasifier

Pre Particulat 

Cooler

Post 

Particulate 

Cooler

From HP 

Economizer 2

To HP Economizer 1

To Superheater

From HP 

Economizer 2

Incinerator 

Exhaust

ASU 

Vent

N2 to GT Combustor

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

97

Exhibit 3-35 Case B1B syngas cleanup heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1B

SHELL GASIFIER

GAS CLEANUP SYSTEM

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Mercury 

Removal

Knock

Out

Drum

Raw Syngas

Sour 

Drum

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Sour Water

Reboiler

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

DWG. NO.

BB-HMB-CS-B1B-PG-2

PAGES

2 OF 3

Sour

Stripper

Syngas

Scrubber

Gross Plant Power: 673 MWe

Auxiliary Load: 177 MWe

Net Plant Power: 497 MWe

Net Plant Efficiency, HHV: 31.2%

Net Plant Heat Rate: 10,927 Btu/kWh

Water

13

16

17

22

23 24

1,256,401 W

450 T

585 P

523 H

27,484 W

100 T

800 P

4 H

436,986 W

550 T

800 P

1,246 H

1,594,881 W

485 T

565 P

424 H

1,266,974 W

94 T

520 P

19 H

Syngas

Coolers

248,650 W

94 T

520 P

70 H

3,022 W

228 T

65 P

370 H

36,563 W

450 T

12 P

479 H

37,925 W

119 T

24 P

37 H

Knock Out

Tailgas to AGR

1,594,881 W

422 T

575 P

663 H

1,239,491 W

95 T

525 P

19 H

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

9,080 W

114 T

11 P

40 H

Treated Syngas

18

Humidification 19 20 Humidified Fuel Gas

8

Shift Steam

High

Temperature

Shift #1

Low

Temperature

Shift #2

Fuel Gas

Humidification

1,157,895 W

376 T

580 P

435 H

1,157,895 W

386 T

575 P

439 H

1,594,881 W

478 T

560 P

421 H

14

15

Two-Stage

Selexol

Clean 

Gas

CO2

Acid 

Gas

Interstage Knockout

21

Multistage 

Intercooled CO2

Compressor

975,038 W

124 T

2,215 P

-70 H

25

Tailgas Recycle

Compressor

Hydrogenation

And Tail Gas 

Cooling

To Fuel Gas 

Preheater

From Fuel Gas 

Preheater

411,354 W

376 T

580 P

380 H

411,354 W

150 T

1,205 P

118 H

4,188 W

94 T

520 P

70 H

333,100 W

278 T

465 P

508 H

333,100 W

380 T

460 P

609 H

From IP BFW, LP 

BFW, and Tail 

Gas Cooling

To Syngas 

Cooling

From Gland Steam 

Condenser

109 T

To LP Turbine, Preheater

WGS/Gasifier Steam 

and Reheater 

29,998 W

120 T

11 P

115 H

To Water 

Treatment

Makeup Water

478,771 W

To Slag Quench

7,250 W

90 T

125 P

11 H

3

7,250 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To 

Deaerator

From IP 

BFW

11,634 W

CO2 Product

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas Scrubber 

and HP Economizer 1

Fuel Gas 

Preheater

Oxygen

Steam

Slip Stream 

to Coal Dryer

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

98

Exhibit 3-36 Case B1B combined cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B1B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B1B

SHELL GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B1B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,911,334 W

101 T

1 P

69 H

8,418,047 W

270 T

15 P

160 H

333,100 W

380 T

460 P

609 H

1,146,042 W

993 T

1,815 P

1,468 H

8,328 W

298 T

65 P

1,171 H

1,393,093 W

440 T

65 P

1,244 H

1,911,334 W

103 T

120 P

71 H

1,400 W

614 T

65 P

1,331 H

1,400 W

212 T

15 P

180 H

21

24

16

23

Hot Well

Condenser 506,076 W

59 T

15 P

27 H

9,028 W

660 T

501 P

1,326 H

9,765 W

614 T

65 P

1,331 H

30,983 W

500 T

250 P

1,255 H

799 W

993 T

1,815 P

1,468 H

1,338 W

504 T

65 P

1,276 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas Cooler To Duct and 

Radiant Syngas 

Coolers

From Duct and Radiant 

Syngas Coolers

To ASU and 

Humidifier

Deaerator

From ASU and 

Humidifier

LP 

Evaporator

IP to Pre Particulate 

and Syngas Coolers

IP From Syngas and Pre 

Particulate Cooler

WGS Shift Steam

From Claus, Process Extraction, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown

LP To Syngas 

Coolers

Cold Reheat

Hot Reheat

8,418,047 W

1,043 T

15 P

372 H

22

To WWT

Condensate to Tail Gas 

Cooling

IP Extraction Steam 

to 250 PSIA Header

Process 

Extraction

LP From 

Syngas Coolers

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

235 T

274 T

1,843,260 W

274 T

45 P

242 H

1,169,363 W

279 T

2,251 P

247 H

9,216 W

274 T

79 P

242 H

25,067 W

274 T

79 P

242 H 271,164 W

274 T

79 P

242 H

41,443 W

276 T

615 P

244 H

282,770 W

351 T

2,251 P

319 H

305 T 585 T 636 T

23,308 W

585 T

2,001 P

585 H

294,918 W

550 T

625 P

1,244 H

325,216 W

550 T

625 P

1,244 H

636 T

480,228 W

585 T

2,001 P

585 H

981,188 W

661 T

501 P

1,327 H

282,770 W

585 T

2,001 P

585 H

290,257 W

298 T

65 P

266 H

217,834 W

298 T

65 P

1,171 H

271,164 W

298 T

65 P

1,171 H

325,216 W

275 T

640 P

243 H

Nitrogen Diluent 1

Fuel Gas

IP To Claus

0 W

30,298 W

550 T

625 P

1,244 H

Gasifier Steam

To Post 

Particulate 

Cooler

From Post 

Particulate 

Cooler

LP Extraction Spray #1

LP Extraction 

Spray #2

Steam to Gasifier 

and WGS

20,429 W

241 T

825 P

209 H 156,625 W

649 T

740 P

1,303 H

1,000 W

993 T

1,815 P

1,468 H 1,000 W

212 T

15 P

180 H

993 T

195 T

Water Makeup

Nitrogen Diluent 2

383,362 W

385 T

384 P

87 H

687,451 W

385 T

469 P

87 H

HP Pump

LP Pump

IP Pump

Gross Plant Power: 673 MWe

Auxiliary Load: 177 MWe

Net Plant Power: 497 MWe

Net Plant Efficiency, HHV: 31.2%

Net Plant Heat Rate: 10,927 Btu/kWh

Condensate

Pumps

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

99

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

100

Exhibit 3-37 Case B1B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,727 

(5,428) 4.8 (4.5) – 5,731 

(5,432)

Air – 118.2 (112.1) – 118.2 

(112.1)

Raw Water Makeup – 80.5 (76.3) – 80.5 (76.3)

Auxiliary Power – – 636 (603) 636 (603)

TOTAL 5,727 

(5,428) 203.5 (192.9) 636 (603) 6,566 

(6,223)

Heat Out (GJ/hr)

ASU Vent – 1.0 (1.0) – 1.0 (1.0)

Slag 22.1 (20.9) 35.7 (33.8) – 57.7 (54.7)

Stack Gas – 1,418 (1,344) – 1,418 

(1,344)

Sulfur 48.9 (46.3) 0.6 (0.6) – 49.5 (46.9)

Motor Losses and Design 

Allowances – – 55.5 (52.6) 55.5 (52.6)

Condenser – 1,335 (1,265) – 1,335 

(1,265)

Non-Condenser Cooling Tower 

Loads – 724 (686) – 724 (686)

CO2 – -71.5 (-67.8) – -71.5 (-67.8)

Blowdown – 41.3 (39.1) – 41.3 (39.1)

CO2 Capture Losses – 171.0 (162.1) – 171.0 

(162.1)

Ambient LossesA – 115.3 (109.3) – 115.3 

(109.3)

Power – – 2,424 

(2,298)

2,424 

(2,298)

TOTAL 71.0 (67.2) 3,769 (3,573) 2,480 

(2,350)

6,320 

(5,990)

Unaccounted EnergyB – 246 (233) – 246 (233)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

3.2.10 Case B1B - Major Equipment List

Major equipment items for the Shell gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

101

estimates in Section 3.2.11. In general, the design conditions include a 10 percent contingency 

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B1B – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 350 tonne/hr (380 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 800 tonne (900 ton) 3 0

Case B1B – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/hr (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/hr (260 tph) 1 0

3 Roller Mill Feed Hopper Dual Outlet 460 tonne (510 ton) 1 0

4 Weigh Feeder Belt 120 tonne/hr (130 tph) 2 0

5 Coal Dryer and Pulverizer Rotary 120 tonne/hr (130 tph) 2 0

6 Coal Dryer Feed Hopper Vertical Hopper 230 tonne (260 ton) 2 0

Case B1B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 987,000 liters (261,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,000 lpm @ 90 m H2O

(2,110 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 551,000 kg/hr (1,215,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

7,970 lpm @ 30 m H2O

(2,110 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

5,060 lpm @ 1,800 m H2O

(1,340 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugalIP water: 1,220 lpm @ 220 m 

H2O (320 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 398 GJ/hr (377 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 142,800 lpm @ 20 m H2O(37,700 gpm @ 70 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

102

Equipment 

No. Description Type Design Condition Operating Qty. Spares

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

5,950 lpm @ 20 m H2O

(1,570 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,980 lpm @ 270 m H2O 

(790 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

4,640 lpm @ 50 m H2O

(1,230 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,226,000 liter (588,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 2,090 lpm (550 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B1B – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized dry-feed, 

entrained bed

2,800 tonne/day, 4.2 MPa

(3,100 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Convective spiralwound tube boiler 397,000 kg/hr (875,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 313,000 kg/hr (691,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 313,000 kg/hr (691,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 398,000 kg/hr (877,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

310,000 kg/hr, 35°C, 3.7 MPa

(683,000 lb/hr, 95°F, 530 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 78 GJ/hr (74 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 83,000 kg/hr, 137°C, 3.6 MPa

(183,000 lb/hr, 278°F, 520 psia) 2 0

10 Saturator Water 

Pump Centrifugal 1,700 lpm @ 13 m H2O(500 gpm @ 42 ft H2O) 2 2

11 Synthesis Gas 

Reheater Shell and tube 83,000 kg/hr (183,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

313,000 kg/hr (691,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 5,000 m3/min @ 1.3 MPa(186,000 scfm @ 190 psia) 2 0

14 Cold Box Vendor design 2,100 tonne/day (2,300 tpd) 

of 95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (37,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,000 m3/min (123,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

103

Equipment 

No. Description Type Design Condition Operating Qty. Spares

17 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

490 m3/min (17,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18

Gasifier Purge 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

1,000 m3/min (48,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0

Case B1B – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 309,000 kg/hr (682,000 lb/hr),

35°C (95°F), 3.6 MPa (525 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 309,000 kg/hr (682,000 lb/hr),

35°C (95°F), 3.6 MPa (520 psia) 2 0

3 Sulfur Plant Claus type 139 tonne/day (154 tpd) 1 0

4 Water Gas Shift 

Reactors Fixed bed, catalytic 199,000 kg/hr (439,000 lb/hr),216°C (420°F), 4.0 MPa (580 psia) 4 0

5

Shift Reactor Heat 

Recovery 

Exchangers

Shell and Tube

Exchanger 1: 121 GJ/hr (114 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

4 0

6 Acid Gas Removal 

Plant Two-stage selexol 316,000 kg/hr (697,000 lb/hr),35°C (94°F), 3.6 MPa (520 psia) 2 0

7 Hydrogenation 

Reactor Fixed bed, catalytic

18,000 kg/hr (40,000 lb/hr)

232°C (450°F)

0.1 MPa (12.2959488 psia)

1 0

8 Tail Gas Recycle 

Compressor Centrifugal 14,000 kg/hr (30,000 lb/hr) each 1 0

9 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

1,100 m3/min @ 15.3 MPa (38,700 

scfm @ 2,215 psia) 4 0

Case B1B – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

Case B1B – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 285,910 kg/hr, 

12.4 MPa/534°C 

(630,323 lb/hr, 1,800 psig/993°F)

2 0

Case B1B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

220 MW

12.4 MPa/534°C/534°C (1,800 psig/ 

993°F/993°F)

1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Equipment 

No. Description Type Design Condition Operating Qty. Spares

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

240 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,470GJ/hr (1,390 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B1B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 440,000 lpm @ 30 m(116,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,450 GJ/hr (2,320 MMBtu/hr) heat duty

1 0

Case B1B – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 222,000 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Lock hopper 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 133,000 liters (35,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 60,000 liters (16,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 190,000 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 60,000 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 210 lpm @ 430 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0

Case B1B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 200 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 74 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 46 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Equipment 

No. Description Type Design Condition Operating Qty. Spares

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B1B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.2.11 Case B1B - Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-38 shows a 

detailed breakdown of the capital costs; Exhibit 3-39 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-40 shows the initial and annual O&M costs; and Exhibit 3-41 shows the COE 

breakdown. 

The estimated TPC of the Shell gasifier with CO2 capture is $3,981/kW. Process contingency 

represents 4.0 percent of the TPC, and project contingency represents 14.1 percent. The COE, 

including CO2 T&S costs of $9.8/MWh, is $162.4/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-38 Case B1B total plant cost details

Case: B1B – Shell IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,425 $0 $2,133 $0 $6,558 $656 $0 $1,443 $8,656 $17

1.2 Coal Stackout & Reclaim $5,718 $0 $1,367 $0 $7,086 $709 $0 $1,559 $9,353 $19

1.3 Coal Conveyors & Yd Crush $5,316 $0 $1,353 $0 $6,669 $667 $0 $1,467 $8,803 $18

1.4 Other Coal Handling $1,391 $0 $313 $0 $1,704 $170 $0 $375 $2,249 $5

1.9 Coal & Sorbent Hnd. Foundations $0 $2,955 $7,723 $0 $10,677 $1,068 $0 $2,349 $14,094 $28

Subtotal $16,851 $2,955 $12,889 $0 $32,694 $3,269 $0 $7,193 $43,156 $87

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying $50,700 $3,058 $7,286 $0 $61,043 $6,104 $0 $13,430 $80,577 $162

2.2 Prepared Coal Storage & Feed $2,401 $577 $371 $0 $3,350 $335 $0 $737 $4,422 $9

2.3 Dry Coal Injection System $79,030 $911 $7,239 $0 $87,180 $8,718 $0 $19,180 $115,078 $232

2.4 Misc. Coal Prep & Feed $1,321 $965 $2,842 $0 $5,127 $513 $0 $1,128 $6,767 $14

2.9 Coal & Sorbent Feed Foundation $0 $4,844 $4,156 $0 $9,000 $900 $0 $1,980 $11,880 $24

Subtotal $133,452 $10,354 $21,894 $0 $165,700 $16,570 $0 $36,454 $218,724 $440

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $2,970 $5,126 $2,687 $0 $10,784 $1,078 $0 $2,372 $14,234 $29

3.2 Water Makeup & Pretreating $857 $89 $471 $0 $1,416 $142 $0 $467 $2,024 $4

3.3 Other Feedwater Subsystems $1,670 $552 $493 $0 $2,715 $271 $0 $597 $3,584 $7

3.4 Service Water Systems $501 $999 $3,443 $0 $4,942 $494 $0 $1,631 $7,068 $14

3.5 Other Boiler Plant Systems $2,699 $1,009 $2,483 $0 $6,191 $619 $0 $1,362 $8,172 $16

3.6 FO Supply Sys & Nat Gas $17,717 $675 $625 $0 $19,017 $1,902 $0 $4,184 $25,103 $51

3.7 Waste Treatment Equipment $1,159 $0 $718 $0 $1,877 $188 $0 $619 $2,683 $5

3.8 Misc. Power Plant Equipment $1,261 $168 $655 $0 $2,085 $208 $0 $688 $2,981 $6

Subtotal $28,834 $8,617 $11,575 $0 $49,026 $4,903 $0 $11,921 $65,849 $133

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $171,383 $0 $73,493 $0 $244,876 $24,488 $33,487 $46,617 $349,467 $704

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $207,843 $0 w/equip. $0 $207,843 $20,784 $0 $22,863 $251,490 $506

4.4 LT Heat Recovery & FG Saturation $30,655 $0 $11,647 $0 $42,303 $4,230 $0 $9,307 $55,840 $112

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,694 $685 $0 $2,379 $238 $0 $523 $3,141 $6

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,672 $5,768 $0 $15,440 $1,544 $0 $4,246 $21,230 $43

Subtotal $409,881 $11,366 $91,593 $0 $512,841 $51,284 $33,487 $83,556 $681,168 $1,371

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $162,818 $0 w/equip. $0 $162,818 $16,282 $32,564 $42,333 $253,996 $511

5A.2 Elemental Sulfur Plant $12,076 $2,354 $15,473 $0 $29,902 $2,990 $0 $6,579 $39,471 $79

5A.3 Mercury Removal $2,022 $0 $1,528 $0 $3,550 $355 $177 $816 $4,899 $10

5A.4 Shift Reactors $8,880 $0 $3,550 $0 $12,429 $1,243 $0 $2,734 $16,406 $33

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case: B1B – Shell IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.6 Blowback Gas Systems $2,562 $431 $241 $0 $3,234 $323 $0 $711 $4,269 $9

5A.7 Fuel Gas Piping $0 $1,043 $683 $0 $1,726 $173 $0 $380 $2,278 $5

5A.9 HGCU Foundations $0 $944 $636 $0 $1,581 $158 $0 $522 $2,261 $5

Subtotal $188,356 $4,773 $22,111 $0 $215,240 $21,524 $32,741 $54,075 $323,580 $651

5B CO2 Compression

5B.2 CO2 Compression & Drying $39,421 $5,913 $16,551 $0 $61,885 $6,188 $0 $13,615 $81,688 $164

Subtotal $39,421 $5,913 $16,551 $0 $61,885 $6,188 $0 $13,615 $81,688 $164

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $316

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $6

Subtotal $111,210 $923 $8,950 $0 $121,083 $12,108 $11,909 $14,948 $160,049 $322

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,630 $0 $5,739 $0 $35,369 $3,537 $0 $3,891 $42,796 $86

7.3 Ductwork $0 $2,111 $1,480 $0 $3,591 $359 $0 $790 $4,740 $10

7.4 Stack $4,074 $0 $1,520 $0 $5,594 $559 $0 $615 $6,769 $14

7.9 HRSG, Duct & Stack Foundations $0 $776 $779 $0 $1,554 $155 $0 $513 $2,222 $4

Subtotal $33,704 $2,887 $9,517 $0 $46,108 $4,611 $0 $5,809 $56,527 $114

8 Steam Turbine Generator

8.1 Steam TG & Accessories $35,245 $0 $4,790 $0 $40,035 $4,003 $0 $4,404 $48,442 $98

8.2 Turbine Plant Auxiliaries $199 $0 $453 $0 $651 $65 $0 $72 $788 $2

8.3 Condenser & Auxiliaries $3,020 $0 $1,697 $0 $4,717 $472 $0 $519 $5,708 $11

8.4 Steam Piping $13,533 $0 $5,869 $0 $19,402 $1,940 $0 $5,335 $26,677 $54

8.9 TG Foundations $0 $937 $1,655 $0 $2,592 $259 $0 $855 $3,707 $7

Subtotal $51,997 $937 $14,463 $0 $67,397 $6,740 $0 $11,185 $85,322 $172

9 Cooling Water System

9.1 Cooling Towers $4,330 $0 $1,310 $0 $5,640 $564 $0 $931 $7,135 $14

9.2 Circulating Water Pumps $2,088 $0 $154 $0 $2,242 $224 $0 $370 $2,836 $6

9.3 Circ. Water System Auxiliaries $183 $0 $26 $0 $208 $21 $0 $34 $264 $1

9.4 Circ. Water Piping $0 $8,098 $1,962 $0 $10,060 $1,006 $0 $2,213 $13,280 $27

9.5 Make-up Water System $475 $0 $653 $0 $1,128 $113 $0 $248 $1,489 $3

9.6 Component Cooling Water Sys $926 $1,107 $760 $0 $2,794 $279 $0 $615 $3,687 $7

9.9 Circ. Water System Foundations $0 $2,651 $4,711 $0 $7,362 $736 $0 $2,429 $10,527 $21

Subtotal $8,001 $11,857 $9,575 $0 $29,434 $2,943 $0 $6,840 $39,217 $79

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $19,503 $0 $9,552 $0 $29,055 $2,905 $0 $3,196 $35,156 $71

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $658 $0 $711 $0 $1,368 $137 $0 $226 $1,731 $3

10.7 Ash Transport & Feed Equipment $905 $0 $211 $0 $1,117 $112 $0 $184 $1,413 $3

10.8 Misc. Ash Handling Equipment $1,362 $1,670 $495 $0 $3,527 $353 $0 $582 $4,462 $9

10.9 Ash/Spent Sorbent Foundation $0 $55 $73 $0 $128 $13 $0 $42 $183 $0

Subtotal $22,428 $1,725 $11,042 $0 $35,195 $3,519 $0 $4,230 $42,945 $86
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case: B1B – Shell IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 497 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11 Accessory Electric Plant

11.1 Generator Equipment $1,096 $0 $1,067 $0 $2,162 $216 $0 $238 $2,616 $5

11.2 Station Service Equipment $5,293 $0 $487 $0 $5,780 $578 $0 $636 $6,994 $14

11.3 Switchgear & Motor Control $9,770 $0 $1,816 $0 $11,586 $1,159 $0 $1,912 $14,657 $30

11.4 Conduit & Cable Tray $0 $4,964 $15,302 $0 $20,266 $2,027 $0 $5,573 $27,866 $56

11.5 Wire & Cable $0 $9,571 $5,823 $0 $15,394 $1,539 $0 $4,233 $21,167 $43

11.6 Protective Equipment $0 $798 $2,963 $0 $3,761 $376 $0 $621 $4,758 $10

11.7 Standby Equipment $263 $0 $262 $0 $525 $53 $0 $87 $664 $1

11.8 Main Power Transformers $18,593 $0 $162 $0 $18,756 $1,876 $0 $3,095 $23,726 $48

11.9 Electrical Foundations $0 $170 $462 $0 $632 $63 $0 $209 $904 $2

Subtotal $35,016 $15,503 $28,345 $0 $78,864 $7,886 $0 $16,603 $103,353 $208

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,274 $0 $868 $0 $2,143 $214 $107 $370 $2,834 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $293 $0 $192 $0 $484 $48 $24 $111 $669 $1

12.7 Computer & Accessories $6,798 $0 $222 $0 $7,020 $702 $351 $807 $8,880 $18

12.8 Instrument Wiring & Tubing $0 $2,617 $4,953 $0 $7,570 $757 $379 $2,176 $10,882 $22

12.9 Other I & C Equipment $4,544 $0 $2,251 $0 $6,796 $680 $340 $1,172 $8,987 $18

Subtotal $12,909 $2,617 $8,487 $0 $24,013 $2,401 $1,201 $4,637 $32,252 $65

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,686 $0 $2,804 $280 $0 $925 $4,010 $8

13.2 Site Improvements $0 $2,101 $2,970 $0 $5,072 $507 $0 $1,674 $7,252 $15

13.3 Site Facilities $3,765 $0 $4,227 $0 $7,992 $799 $0 $2,637 $11,429 $23

Subtotal $3,765 $2,219 $9,883 $0 $15,868 $1,587 $0 $5,236 $22,691 $46

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,481 $3,532 $0 $6,014 $601 $0 $992 $7,607 $15

14.3 Administration Building $0 $1,027 $745 $0 $1,772 $177 $0 $292 $2,242 $5

14.4 Circulation Water Pumphouse $0 $193 $102 $0 $295 $29 $0 $49 $373 $1

14.5 Water Treatment Buildings $0 $704 $686 $0 $1,391 $139 $0 $229 $1,759 $4

14.6 Machine Shop $0 $526 $360 $0 $885 $89 $0 $146 $1,120 $2

14.7 Warehouse $0 $849 $548 $0 $1,397 $140 $0 $230 $1,767 $4

14.8 Other Buildings & Structures $0 $508 $396 $0 $904 $90 $0 $199 $1,193 $2

14.9 Waste Treating Building & Str. $0 $1,137 $2,171 $0 $3,307 $331 $0 $728 $4,366 $9

Subtotal $0 $7,742 $8,718 $0 $16,460 $1,646 $0 $2,975 $21,081 $42

Total $1,095,825 $90,388 $285,594 $0 $1,471,807 $147,181 $79,338 $279,277 $1,977,603 $3,981
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-39 Case B1B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $15,919 $32

1 Month Maintenance Materials $3,587 $7

1 Month Non-fuel Consumables $682 $1

1 Month Waste Disposal $434 $1

25% of 1 Months Fuel Cost at 100% CF $2,910 $6

2% of TPC $39,552 $80

Total $63,083 $127

Inventory Capital

60-day supply of fuel and consumables at 100% CF $24,228 $49

0.5% of TPC (spare parts) $9,888 $20

Total $34,116 $69

Other Costs

Initial Cost for Catalyst and Chemicals $16,739 $34

Land $900 $2

Other Owner's Costs $296,640 $597

Financing Costs $53,395 $107

Total Overnight Costs (TOC) $2,442,476 $4,917

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,784,423 $5,605
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

110

Exhibit 3-40 Case B1B initial and annual operating and maintenance costs

Case: B1B – Shell IGCC w/ CO2 Cost Base: Jun 2011

Plant Size (MW,net): 497 Heat Rate-net (Btu/kWh): 10,927 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 10.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 16.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,233,658 $14.562

Maintenance Labor: $18,236,067 $36.711

Administrative & Support Labor: $6,367,431 $12.818

Property Taxes and Insurance: $39,552,053 $79.623

Total: $71,389,208 $143.715

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $34,437,835 $9.89265

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 4,070 $1.67 $0 $1,989,343 $0.57146

Makeup and Waste Water 

Treatment Chemicals (lbs):

0 24,247 $0.27 $0 $1,896,308 $0.54474

Carbon (Mercury Removal) (lb): 201,639 345 $5.50 $1,109,016 $554,508 $0.15929

Shift Catalyst (ft3): 6,470 4.43 $771.99 $4,994,685 $998,937 $0.28696

Selexol Solution (gal): 289,068 92 $36.79 $10,635,172 $989,212 $0.28416

Claus Catalyst (ft3): w/equip. 1.93 $203.15 $0 $114,583 $0.03292

Subtotal: $16,738,872 $6,542,891 $1.87952

Waste Disposal

Spent Mercury Catalyst (lb.): 0 345 $0.65 $0 $65,542 $0.01883

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 559 $25.11 $0 $4,099,990 $1.17777

 Subtotal: $0 $4,165,532 $1.19660

By-Products

Sulfur (tons): 0 140 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $16,738,872 $45,146,258 $12.96876

Fuel Cost

Illinois Number 6 (ton): 0 5,583 $68.54 $0 $111,739,739 $32.09848

Total: $0 $111,739,739 $32.09848

Exhibit 3-41 Case B1B COE breakdown

Component Value, $/MWh Percentage

Capital 87.0 57%

Fixed 20.5 13%

Variable 13.0 8%

Fuel 32.1 21%

Total (Excluding T&S) 152.6 N/A

CO2 T&S 9.8 6%

Total (Including T&S) 162.4 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

111

3.3 CB&I E-GasTM IGCC Cases

This section contains an evaluation of plant designs for cases B4A and B4B, which are based on 

the CB&I E-GasTM gasifier. Cases B4A and B4B are very similar in terms of process, 

equipment, scope and arrangement, except that Case B4B includes SGS reactors, CO2

absorption/regeneration and compression/transport systems. There are no provisions for CO2

removal in Case B4A.

The balance of this section is organized in an analogous manner to Section 3.2:

• Gasifier Background

• Process System Description for Case B4A

• Key Assumptions for Cases B4A and B4B

• Sparing Philosophy for Cases B4A and B4B

• Performance Results for Case B4A

• Equipment List for Case B4A

• Cost Estimates for Case B4A

• Process and System Description, Performance Results, Equipment List, and Cost 

Estimate for Case B4B

3.3.1 Gasifier Background

As mentioned in Section 3.2.1, the “Coal Gasification Guidebook: Status, Application, and 

Technologies” report published by EPRI provides a detailed history of the development of 

several types of gasifier technology, including the Shell gasifier, as well as gasifier capacity, 

distinguishing characteristics, and important coal characteristics. (46)

In January of 2000, CB&I completed construction of an E-GASTM demonstration facility, located 

at the Wabash River Generating Station in West Terre Haute, Indiana. It is still operational as a 

baseload unit. (39)

The Wabash River unit has a coal handling capacity of 1,678 tonnes/day (1,850 tons/day) – on a 

moisture and ash-free (MAF) basis – for bituminous coal with a high sulfur content. The unit 

produces dry gas at a rate of 189,724 Nm3/hr (6.7 million scf/hr) with an energy content of about 

1,950 GJ/hr (1,850 MMBtu/hr) (HHV). This size matches the CT, which is a GE 7FA. (46)

The E-GasTM gasifier has significant operating experience with bituminous coal at full 

commercial scale via the Wabash plant. (46)

Compared to a single stage slurry-fed gasifier, the E-GasTM technology demonstrates superior 

efficiency and lower oxygen requirements. (46)

Notable characteristics of the E-GasTM gasifier are the relatively short refractory life and the high 

waste heat recovery rate, resulting from the high operating temperature. The E-GasTM gasifier 

produces a syngas with a higher CH4 content than other single-stage slurry fed gasifiers, due to 

the use of quenching in the second stage. However, in CO2 capture cases the CH4 passes through 

the SGS reactors without change, and is also not separated by the AGR thus limiting the amount 

of carbon that can be captured. (46)

Bituminous coals with low moisture content are desired for use with the E-GasTM gasifier as it 

benefits the slurry concentration and lowers the oxygen requirement. As with all slagging 

gasifiers, low concentrations of ash with low to moderate ash fusion temperatures are preferred.

(46)
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3.3.2 Process Description

In this section the overall E-GasTM gasification process is described. The system description 

follows the BFD in Exhibit 3-42 and stream numbers reference the same exhibit. The tables in 

Exhibit 3-43 provide process data for the numbered streams in the BFD.

3.3.2.1 Coal Grinding and Slurry Preparation

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal grinding and slurry preparation is 

similar to the GEE cases but repeated here for completeness.

Coal from the coal silo is fed onto a conveyor by vibratory feeders located below each silo. The 

conveyor feeds the coal to an inclined conveyor that delivers the coal to the rod mill feed hopper. 

The feed hopper provides a surge capacity of about two hours and contains two hopper outlets. 

Each hopper outlet discharges onto a weigh feeder, which in turn feeds a rod mill. Each rod mill 

is sized to process 55 percent of the coal feed requirements of the gasifier. The rod mill grinds 

the coal and wets it with treated slurry water transferred from the slurry water tank by the slurry 

water pumps. The coal slurry is discharged through a trommel screen into the rod mill discharge 

tank, and then the slurry is pumped to the slurry storage tanks. The dry solids concentration of 

the final slurry is 63 percent. The Polk Power Station operates at a slurry concentration of 62-68 

percent using bituminous coal, and ConocoPhillips presented a paper showing the slurry 

concentration of Illinois No. 6 coal as 63 percent. (49) 

The coal grinding system is equipped with a dust suppression system consisting of water sprays 

aided by a wetting agent. The degree of dust suppression required depends on local 

environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal 

slurry solids suspended.

The equipment in the coal grinding and slurry preparation system is fabricated of materials 

appropriate for the abrasive environment present in the system. The tanks and agitators are 

rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping 

is fabricated of HDPE.

3.3.2.2 Gasification

This plant utilizes two gasification trains to process a total of 5,007 tonnes/day (5,519 tpd) of 

Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operate at maximum capacity. The EGasTM two-stage coal gasification technology features an oxygen-blown, entrained-flow, 

refractory-lined gasifier with continuous slag removal. About 78 percent of the total slurry feed 

is fed to the first (or bottom) stage of the gasifier. The air separation plant supplies 3,711 

tonnes/day (4,090 tpd) of 95 percent oxygen to the gasifiers (stream 5) and the Claus plant 

(stream 3). All oxygen for gasification is fed to this stage of the gasifier at a pressure of 4.2 MPa 

(615 psia). This stage is best described as a horizontal cylinder with two horizontally opposed 

burners. The highly exothermic gasification/oxidation reactions take place rapidly at 

temperatures of 1,316 to 1,427°C (2,400 to 2,600°F). The hot raw gas from the first stage enters 

the second (top) stage, which is a vertical cylinder perpendicular to the first stage. The 

remaining 22 percent of coal slurry is injected into this hot raw gas. The endothermic 

gasification/devolatilization reaction in this stage reduces the gasifier exit temperature to about 

1,038°C (1,900°F). Total slurry to both stages is shown as stream 7 in Exhibit 3-42.
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Exhibit 3-42 Case B4A block flow diagram, E-GasTM IGCC without CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

COS

HYDROLYSIS

ELEVATED

PRESSURE

ASU

E-GASTM

GASIFIER

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

MDEA CLAUS

PLANT

SYNGAS

REHEAT

HRSG

2X STATE-OF-THEART F-CLASS

GAS TURBINES

1

AIR TO ASU

2 3

VENT

GAS

5

7

GASIFIER

OXIDANT

AS-RECEIVED

COAL

SLAG

10

11 12

17

18

14

16

4

21

22

TURBINE COOLING AIR

23 24

WATER RECYCLE TO

SLURRY PREPARATION

FLUE GAS

STACK GAS

HYDROGENATION

REACTOR AND GAS

COOLER

19

TAIL GAS RECYCLE TO

MDEA

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, BUT

NOT SHOWN

CLEAN GAS

NITROGEN DILUENT

AIR EXTRACTION

SULFUR

PRODUCT

SYNGAS

NOTE: FLASH GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

NOTE: SYNGAS RECYCLE

COMPRESSOR MODELED, 

BUT NOT SHOWN

NOTE: ACID GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

TAIL GAS

SYNGAS

COOLING, 

CYCLONES & 

FILTERS

SYNGAS

HUMIDIFICATION

15

RECYCLE TO

GASIFIER

CLAUS

PLANT

OXIDANT

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

25 Note: Block Flow Diagram is not 

intended to represent a complete 

material balance. Only major process 

streams and equipment are shown.

SLURRY

MIXER

8

9

20

13

TAIL GAS RECYCLE

FROM CLAUS PLANT

6 STEAM
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Exhibit 3-43 Case B4A stream table, E-GasTM IGCC without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0241 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0078 0.0078 0.0096 0.0095 0.0098

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0465 0.0465 0.0575 0.0555 0.0576

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3011 0.3011 0.3727 0.3597 0.3734

CO2 0.0003 0.0083 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1556 0.1559 0.1929 0.2137 0.1931

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2725 0.2725 0.3372 0.3299 0.3425

H2O 0.0099 0.2164 0.0000 0.0003 0.0000 1.0000 0.0000 0.9968 0.0000 0.1888 0.1885 0.0015 0.0015 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0002 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0072 0.0075 0.0092 0.0090 0.0000

N2 0.7732 0.5456 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0157 0.0157 0.0194 0.0213 0.0221

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0032 0.0000 0.0045 0.0045 0.0000 0.0000 0.0000

O2 0.2074 0.2055 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 18,975 915 111 17,428 4,694 3,766 0 4,758 0 21,815 21,815 17,626 18,275 17,601

V-L Flowrate (kg/hr) 547,573 24,798 3,567 489,025 151,055 67,847 0 85,706 0 459,698 459,698 384,238 408,328 380,348

Solids Flowrate (kg/hr) 0 0 0 0 0 0 208,633 0 21,295 0 0 0 0 0

Temperature (°C) 15 20 32 93 32 343 15 149 1,038 186 186 35 34 45

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.10 0.10 5.79 4.24 4.07 4.00 3.83 3.79 3.76

Steam Table Enthalpy (kJ/kg) A 30.23 36.92 26.67 92.52 26.67 3,063.97 --- 567.36 --- 673.89 673.68 39.55 36.82 55.08

AspenPlus Enthalpy (kJ/kg)B -97.58 -2,404.24 4.13 63.38 4.13 -12,907.38 -2,116.95 -15,363.86 1,005.43 -6,602.13 -6,602.13 -5,592.59 -5,753.40 -5,625.00

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 20.1 --- 862.4 --- 22.7 22.3 33.0 33.7 31.0

V-L Molecular Weight 28.857 27.090 32.181 28.060 32.181 18.015 --- 18.012 --- 21.073 21.073 21.799 22.344 21.610

V-L Flowrate (lbmole/hr) 41,834 2,018 244 38,422 10,348 8,303 0 10,490 0 48,093 48,093 38,859 40,289 38,803

V-L Flowrate (lb/hr) 1,207,192 54,670 7,864 1,078,115 333,020 149,578 0 188,950 0 1,013,462 1,013,462 847,100 900,209 838,525

Solids Flowrate (lb/hr) 0 0 0 0 0 0 459,956 0 46,947 0 0 0 0 0

Temperature (°F) 59 69 90 199 90 650 59 300 1,900 367 367 95 94 112

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 740.0 14.7 840.0 615.0 590.0 580.0 555.0 550.0 545.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.9 11.5 39.8 11.5 1,317.3 --- 243.9 --- 289.7 289.6 17.0 15.8 23.7

AspenPlus Enthalpy (Btu/lb)B -42.0 -1,033.6 1.8 27.2 1.8 -5,549.2 -910.1 -6,605.3 432.3 -2,838.4 -2,838.4 -2,404.4 -2,473.5 -2,418.3

Density (lb/ft3) 0.076 0.098 0.687 1.521 0.687 1.257 --- 53.837 --- 1.416 1.391 2.061 2.105 1.938

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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Exhibit 3-43 Case B4A stream table, E-GasTM IGCC without capture (continued)

15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0085 0.0085 0.0000 0.0000 0.0041 0.0055 0.0092 0.0092 0.0087 0.0087 0.0000

CH4 0.0500 0.0500 0.0002 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.3241 0.3241 0.0010 0.0000 0.0848 0.0061 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.1676 0.1676 0.7537 0.0000 0.4983 0.7790 0.0003 0.0003 0.0803 0.0803 0.0000

COS 0.0000 0.0000 0.0001 0.0000 0.0003 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.2973 0.2973 0.0009 0.0000 0.0209 0.1311 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.1333 0.1333 0.0000 0.0000 0.3350 0.0018 0.0099 0.0099 0.0860 0.0860 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.2443 0.0000 0.0014 0.0043 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0192 0.0192 0.0000 0.0000 0.0537 0.0723 0.7732 0.7732 0.7250 0.7250 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1000 0.1000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 20,276 20,276 674 0 873 649 110,253 4,410 137,247 137,247 40,181

V-L Flowrate (kg/hr) 428,547 428,547 27,980 0 28,108 24,090 3,181,557 127,262 3,971,867 3,971,867 723,870

Solids Flowrate (kg/hr) 0 0 0 5,215 0 0 0 0 0 0 0

Temperature (°C) 143 193 45 175 232 38 15 432 588 132 561

Pressure (MPa, abs) 3.21 3.17 3.76 0.41 0.41 5.51 0.10 1.62 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 489.40 569.86 -0.67 --- 731.47 -6.63 30.23 463.79 783.86 272.30 3,500.61

AspenPlus Enthalpy (kJ/kg)B -6,348.13 -6,267.67 -7,288.11 140.10 -8,672.98 -8,318.28 -97.58 335.98 -1,186.76 -1,698.31 -12,469.70

Density (kg/m3) 19.7 17.3 73.5 5,285.4 3.1 96.3 1.2 7.9 0.4 0.9 35.2

V-L Molecular Weight 21.135 21.135 41.529 --- 32.209 37.141 28.857 28.857 28.940 28.940 18.015

V-L Flowrate (lbmole/hr) 44,702 44,702 1,485 0 1,924 1,430 243,066 9,723 302,577 302,577 88,584

V-L Flowrate (lb/hr) 944,784 944,784 61,685 0 61,967 53,109 7,014,133 280,565 8,756,467 8,756,467 1,595,860

Solids Flowrate (lb/hr) 0 0 0 11,497 0 0 0 0 0 0 0

Temperature (°F) 290 380 112 347 450 100 59 810 1,091 270 1,041

Pressure (psia) 465.0 460.0 545.0 59.3 58.9 799.5 14.7 234.9 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 210.4 245.0 -0.3 --- 314.5 -2.8 13.0 199.4 337.0 117.1 1,505.0

AspenPlus Enthalpy (Btu/lb)B -2,729.2 -2,694.6 -3,133.3 60.2 -3,728.7 -3,576.2 -42.0 144.4 -510.2 -730.1 -5,361.0

Density (lb/ft3) 1.230 1.081 4.586 329.954 0.195 6.012 0.076 0.495 0.026 0.056 2.194

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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The syngas produced by the E-GasTM gasifier is higher in methane content than either the GEE 

or Shell gasifier. The two-stage design allows for improved cold gas efficiency (CGE) and lower 

oxygen consumption, but the quenched second stage allows some CH4 to remain. The syngas 

CH4 concentration exiting the gasifier in Case B4A is 4.3 vol% (compared to 0.10 vol% in Case 

B5A [GEE] and 0.001 vol% in Case B1A [Shell]). The relatively high CH4 concentration 

impacts carbon capture efficiency as discussed in Section 3.3.8.

3.3.2.3 Raw Gas Cooling/Particulate Removal

The raw syngas, less than 1,038°C (1,900°F), from the second stage of the gasifier is cooled to 

316°C (600°F) in the waste heat recovery (SGC) unit, which consists of a fire-tube boiler and 

convective superheating and economizing sections. 554,830 kg/hr (1,223,171 lb/hr) of HP 

saturated steam is raised as a result of the raw gas cooling. Fire-tube boilers cost markedly less 

than comparable duty water-tube boilers. This is because of the large savings in high-grade steel 

associated with containing the hot HP syngas in relatively small tubes.

The coal ash is converted to molten slag, which flows down through a tap hole. The molten slag 

is quenched in water and removed through a proprietary continuous-pressure letdown/dewatering 

system (stream 9). Char is produced in the second gasifier stage and is captured and recycled to 

the hotter first stage to be gasified.

The cooled gas from the SGC is cleaned of remaining particulate via a cyclone collector 

followed by a ceramic candle filter. Recycled syngas is used as the pulse gas to clean the candle 

filters. The recovered fines are pneumatically returned to the first stage of the gasifier. The 

combination of recycled char and recycled particulate results in high overall carbon conversion 

(99.2 percent used in this report). 

Following particulate removal, additional heat is removed from the syngas to raise saturated IP 

steam at 0.4 MPa (65 psia). In this manner the syngas is cooled to 232°C (450°F) prior to the 

syngas scrubber.

3.3.2.4 Syngas Scrubber/Sour Water Stripper

Syngas exiting the second of the two low-temperature heat exchangers passes to a syngas 

scrubber where a water wash is used to remove chlorides, SO2, NH3, and particulate. The syngas 

exits the scrubber saturated at 169°C (337°F).

The sour water stripper removes NH3, SO2, and impurities from the scrubber and other waste 

streams. The stripper consists of a sour drum that accumulates sour water from the gas scrubber 

and condensate from SGCs. Sour water from the drum flows to the sour stripper, which consists 

of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid and sent to 

the SRU. Remaining water is sent to wastewater treatment.

3.3.2.5 COS Hydrolysis, Mercury Removal and Acid Gas Removal

Syngas exiting the scrubber is reheated to 186°C (367°F) by using HP steam from the HRSG 

evaporator prior to entering a COS hydrolysis reactor (stream 10). About 99.5 percent of the 

COS is converted to CO2 and H2O (Section 3.1.5). The gas exiting the COS reactor (stream 11) 

passes through a series of heat exchangers and KO drums to lower the syngas temperature to 

35°C (95°F) and to separate entrained water. The cooled syngas (stream 12) then passes through 

a carbon bed to remove approximately 97 percent of the Hg (Section 3.1.4).
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Cool, particulate-free syngas (stream 13) enters the absorber unit at approximately 3.8 MPa 

(550 psia) and 34°C (94°F). In the absorber, H2S is preferentially removed from the fuel gas 

stream by contact with MDEA. The absorber column is operated at 44°C (112°F) by 

refrigerating the lean MDEA solvent. The lower temperature is required to achieve an outlet H2S 

concentration of less than 30 ppmv in the sweet syngas. The stripper acid gas stream (stream 

17), consisting of 24 percent H2S and 75 percent CO2, is sent to the Claus unit. The acid gas is 

combined with the sour water stripper off gas and introduced into the Claus plant burner section.

3.3.2.6 Claus Unit

Acid gas from the MDEA unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature of 1,316°C 

(2,400°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheaters and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.5 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the gasifier (stream 20). In the furnace waste heat 

boiler, 13,866 kg/hr (30,568 lb/hr) of 3.0 MPa (430 psia) steam is generated. This steam is used 

to satisfy all Claus process preheating and reheating requirements as well as to provide some 

steam to the medium-pressure steam header. The sulfur condensers produce 0.34 MPa (50 psig) 

steam for the LP steam header and IP steam at 2.9 MPa (415 psig).

A flow rate of 5,215 kg/hr (11,497 lb/hr) of elemental sulfur (stream 18) is recovered from the 

fuel gas stream. This value represents an overall sulfur recovery efficiency of 99.7 percent.

3.3.2.7 Power Block

Clean syngas exiting the MDEA absorber (stream 14) is partially humidified (stream 15) because 

there is not sufficient nitrogen from the ASU to provide the level of dilution required to reach the 

target syngas heating value. The moisturized syngas stream is reheated (stream 16), further 

diluted with nitrogen from the ASU (stream 4) and enters the state-of-the-art 2008 F-class CT 

burner. The CT compressor provides combustion air to the burner and also 19 percent of the 

total ASU air requirement (stream 22). The exhaust gas exits the CT at 588°C (1,091°F) (stream 

23) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 

132°C (270°F) (stream 24) and is discharged through the plant stack. The steam raised in the 

HRSG is used to power an advanced, commercially available steam turbine using a 12.4 

MPa/561°C/561°C (1,800 psig/1,041°F/1,041°F) steam cycle.

3.3.2.8 Air Separation Unit

The elevated pressure ASU was described in Section 3.1.2. In Case B4A, the ASU is designed 

to produce a nominal output of 3,711 tonnes/day (4,091 tpd) of 95 mol% O2 for use in the 

gasifier (stream 5) and Claus plant (stream 3). The plant is designed with two production trains. 

The air compressor is powered by an electric motor. Approximately 11,736 tonnes/day 

(12,937 tpd) of nitrogen is also recovered, compressed, and used as dilution in the CT combustor 

(stream 4). About 4 percent of the CT air is used to supply approximately 19 percent of the ASU 

air requirements (stream 22) in the non-capture case.
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118

3.3.2.9 Balance of Plant

Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.12.

3.3.3 Key System Assumptions

System assumptions for cases B4A and B4B, E-GasTM IGCC with and without CO2 capture, are 

compiled in Exhibit 3-44.

3.3.3.1 Balance of Plant – Cases B4A and B4B

The balance of plant assumptions are common to all cases and were presented previously in 

Exhibit 3-11.

3.3.4 Sparing Philosophy

The sparing philosophy for cases B4A and B4B is provided below. Dual trains are used to 

accommodate the size of commercial CTs. There is no redundancy other than normal sparing of 

rotating equipment. The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, cyclone, and candle filter (2 x 50%) 

• Two trains of syngas clean-up process (2 x 50%)

• Two trains of refrigerated MDEA AGR in Case B4A and two-stage Selexol in Case B4B 

(2 x 50%)

• Two CO2 compression systems (2 x 50%) in Case B4B

• One train of Claus-based sulfur recovery (1 x 100%) 

• Two CT/HRSG tandems (2 x 50%)

• One steam turbine (1 x 100%)
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119

Exhibit 3-44 E-GasTM IGCC plant study configuration matrix

Case B4A B4B

Gasifier Pressure, MPa (psia) 4.2 (615) 4.2 (615)

O2:Coal Ratio, kg O2/kg dry coal 0.81 0.88

Carbon Conversion, % 99.2 99.2

Syngas HHV at Gasifier Outlet, kJ/Nm3

(Btu/scf) 8,319 (223) 7,021 (189)

Steam Cycle, MPa/°C/°C (psig/°F/°F) 12.4/561/561 (1,800/1,041/1,041) 12.4/534/534 (1,800/994/994)

Condenser Pressure, mm Hg (in Hg) 51 (2.0) 51 (2.0)

CT 2x State-of-the-Art 2008 F-Class 

(232 MW output each)

2x State-of-the-Art 2008 F-Class 

(232 MW output each)

Gasifier Technology CB&I E-GasTM CB&I E-GasTM

Oxidant 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content, % 63 63

COS Hydrolysis Yes Occurs in SGS

SGS No Yes

H2S Separation Refrigerated MDEA Selexol 1st Stage

Sulfur Removal, % 99.7 99.9

Sulfur Recovery Claus Plant with Tail Gas Recycle 

to Gasifier/ Elemental Sulfur

Claus Plant with Tail Gas Recycle 

to Gasifier/ Elemental Sulfur

Particulate Control Cyclone, Candle Filter, Scrubber, 

and AGR Absorber

Cyclone, Candle Filter, Scrubber, 

and AGR Absorber

Mercury Control Carbon Bed Carbon Bed

NOx Control MNQC (LNB), N2 Dilution and 

Humidification

MNQC (LNB), N2 Dilution and 

Humidification

CO2 Separation N/A Selexol 2nd Stage

Overall Carbon Capture N/A 89.9%

CO2 Sequestration N/A Off-site Saline Formation

3.3.5 Case B4A - Performance Results

The plant produces a net output of 625 MWe at a net plant efficiency of 39.7 percent (HHV 

basis). 

Overall performance for the entire plant is summarized in Exhibit 3-45; Exhibit 3-46 provides a 

detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 

76 percent of the total auxiliary load distributed between the main air compressor, oxygen 

compressor, nitrogen compressor, and ASU auxiliaries. The cooling water system, including the 

CWPs and cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

120

BFW pumps account for an additional 3.9 percent. All other individual auxiliary loads are less 

than 3.5 percent of the total.

Exhibit 3-45 Case B4A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 274

Total Gross Power, MWe 738

Air Separation Unit Main Air Compressor, kWe 46,700

Oxygen Compressor, kWe 7,920

Nitrogen Compressors, kWe 29,910

CO2 Compression, kWe 0

Acid Gas Removal, kWe 3,150

Balance of Plant, kWe 25,530

Total Auxiliaries, MWe 113

Net Power, MWe 625

HHV Net Plant Efficiency (%) 39.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,058 (8,585)

HHV Cold Gas Efficiency, % 82.0%

HHV Combustion Turbine Efficiency, % 37.2%

LHV Net Plant Efficiency (%) 41.2%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,737 (8,281)

LHV Cold Gas Efficiency, % 78.2%

LHV Combustion Turbine Efficiency, % 40.4%

Steam Turbine Cycle Efficiency, % 45.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 7,951 (7,536)

Condenser Duty, GJ/hr (MMBtu/hr) 1,415 (1,341)

As-Received Coal Feed, kg/hr (lb/hr) 208,633 (459,956)

HHV Thermal Input, kWt 1,572,575

LHV Thermal Input, kWt 1,516,768

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.027 (7.0)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.021 (5.6)

O2:Coal 0.684
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

121

Exhibit 3-46 Case B4A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 274

Total Gross Power, MWe 738

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,150

Sour Water Recycle Slurry Pump, kWe 180

Slag Handling, kWe 1,100

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 46,700

Oxygen Compressor, kWe 7,920

Nitrogen Compressors, kWe 29,910

Feedwater Pumps, kWe 4,410

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 810

CO2 Compression, kWe 0

Scrubber Pumps, kWe 320

Acid Gas Removal, kWe 3,150

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 240

Circulating Water Pumps, kWe 3,890

Ground Water Pumps, kWe 400

Cooling Tower Fans, kWe 2,010

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,610

Miscellaneous Balance of PlantA, kWe 3,000

Transformer Losses, kWe 2,600

Total Auxiliaries, MWe 113

Net Power, MWe 625

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.3.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section

2.3. A summary of the plant air emissions for Case B4A is presented in Exhibit 3-47. All HCl is 

assumed to be removed and is, therefore, not reported. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

122

Exhibit 3-47 Case B4A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.005 (0.012) 200 (220) 0.039 (0.085)

NOx 0.026 (0.060) 1,017 (1,122) 0.197 (0.434)

Particulates 0.003 (0.0071) 121 (133) 0.023 (0.052)

Hg 1.77E-7 (4.13E-7) 0.007 (0.008) 1.36E-6 (3.00E-6)

CO2 86 (199) 3,398,347 (3,746,036) 657 (1,448)

CO2C - - 776 (1,711)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 in the plant emissions is achieved by capturing the sulfur in the gas by the 

refrigerated MDEA AGR process. The AGR process removes 99.7 percent of the sulfur 

compounds in the fuel gas down to a level of less than 30 ppmv. This results in a concentration 

in the flue gas of less than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed 

to a Claus plant, producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert 

all sulfur species to H2S and then recycled back to the gasifier, thereby eliminating the need for a 

tail gas treatment unit.

NOx emissions are limited by the use of nitrogen dilution (primarily) and humidification (to a 

lesser extent) to 15 ppmvd (as NO2 @ 15 percent O2). Ammonia in the syngas is removed with 

process condensate prior to the low-temperature AGR process and destroyed in the Claus plant 

burner. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-48. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the slag and as CO2 in the stack gas and ASU vent gas. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

123

Exhibit 3-48 Case B4A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 132,992 (293,198) Stack Gas 132,344 (291,768)

Air (CO2) 507 (1,118) CO2 Product 0 (0)

ASU Vent 92 (202)

Slag 1,064 (2,346)

Total 133,499 (294,316) Total 133,499 (294,316)

Exhibit 3-49 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-49 Case B4A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,229 (11,528) Stack Gas 14 (31)

CO2 Product 0 (0)

Elemental Sulfur 5,215 (11,497)

Total 5,229 (11,528) Total 5,229 (11,528)

Exhibit 3-50 shows the overall water balance for the plant. The water balance was explained in 

Case B1A [Shell], but is also presented here for completeness.

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process, primarily as syngas condensate, and is re-used as internal 

recycle. The difference between demand and recycle is raw water withdrawal. Raw water 

withdrawal is defined as the water removed from the ground or diverted from a surface-water 

source for use in the plant and was assumed to be provided 50 percent by a POTW and 50 

percent from groundwater. Raw water withdrawal can be represented by the water metered from 

a raw water source and used in the plant processes for any and all purposes, such as cooling 

tower makeup, BFW makeup, quench system makeup, and slag handling makeup. The 

difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source balance.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

124

Exhibit 3-50 Case B4A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.46 (122) 0.46 (122) – – –

Slurry Water 1.43 (378) 0.99 (262) 0.44 (115) – 0.44 (115)

Quench/Wash – – – – –

Humidifier 0.84 (222) 0.84 (222) – – –

SWS Blowdown – – – 0.01 (3.84) -0.01 (-3.84)

Condenser Makeup 1.34 (354) – 1.34 (354) – 1.34 (354)

 BFW Makeup 0.21 (55) – 0.21 (55) – 0.21 (55)

 Gasifier Steam 1.13 (299) – 1.13 (299) – 1.13 (299)

 Shift Steam – – – – –

 CT Steam Dilution – – – – –

Cooling Tower 15.16 

(4,006) 0.35 (93) 14.81 (3,913) 3.41 (901) 11.40 (3,012)

 BFW Blowdown – 0.21 (55) -0.21 (-55) – -0.21 (-55)

 SWS Blowdown – 0.15 (38.44) -0.15 (-

38.44) – -0.15 (-38.44)

Total 19.24 

(5,082) 2.65 (700) 16.59 (4,382) 3.42 (905) 13.16 (3,477)

3.3.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-51 through 

Exhibit 3-53:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-54. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-45) is calculated by multiplying the power out by a combined 

generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

125

Exhibit 3-51 Case B4A coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4A

COP GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-B4A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

1,207,192 W

59 T

15 P

13 H

333,020 W

90 T

125 P

11 H

333,020 W

223 T

740 P

38 H

To Claus Plant

7,864 W

90 T

125 P

11 H

54,670 W

69 T

16 P

16 H

957,130 W

90 T

56 P

14 H

133,997 W

50 T

182 P

3 H

5

1

3

2

Candle Filter

Slurry Mix 

Tank

E-Gas TM

Gasifier

Milled Coal

Water

Slag

Cyclones

Fire

Tube

459,956 W Boiler

59 T

15 P

188,950 W

300 T

840 P

244 H

46,947 W

1,900 T

615 P

1,241,587 W

600 T

605 P

422 H

9

648,906 W

162 T

840 P

1,241,587 W

600 T

605 P

422 H

1,241,587 W

1,834 T

615 P

969 H

144,018 W

159 T

800 P

37 H

1,241,587 W

450 T

600 P

361 H

1,206,115 W

100 T

190 P

18 H

7

8

Steam

149,578 W

650 T

740 P

1,309 H

Syngas Recycle

Compressor 144,018 W

105 T

600 P

19 H

From LP 

Economizer

To LP 

Evaporator

1,061,557 W

450 T

600 P

361 H

6

280,565 W

220 T

225 P

51 H

280,565 W

810 T

235 P

199 H

1,078,115 W

389 T

384 P

88 H

Air From GT 

Compressor

N2 to GT Combustor

From HP 

Economizer 2

To HP Economizer 1

13,012 W

376 T

785 P

84 H

Boost 

Compressor

22

1,078,115 W

199 T

384 P

40 H

4

To Superheater

From HP 

Economizer 2

Post 

Particulate 

Cooler

Raw 

Syngas 

to Scrubber

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

Net Plant Heat Rate: 8,585 Btu/kWh

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

126

Exhibit 3-52 Case B4A syngas cleanup heat and mass balance schematic

Source: NETL

Mercury 

Removal

Knock

Out 

Drum

Raw Syngas

Humidified Fuel Gas

Sour

Drum

To Coal Slurry and Slag Quench

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

From 

ASU

Syngas

Coolers

Sour

Stripper

Syngas

Scrubber

1,061,557 W

450 T

600 P

361 H

1,013,462 W

337 T

595 P

284 H

900,209 W

94 T

550 P

16 H

944,784 W

290 T

465 P

210 H

61,685 W

112 T

545 P

0 H

944,784 W

380 T

460 P

245 H

11,497 W 61,967 W

450 T

59 P

314 H

3,916 W

191 T

65 P

190 H

7,864 W

90 T

125 P

11 H

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4A

COP GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-B4A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

2 OF 3

14

18

12

16

20

847,100 W

95 T

555 P

17 H

8,858 W

119 T

57 P

45 H

3

53,109 W

100 T

800 P

-3 H

Humidification 15

838,525 W

112 T

545 P

24 H

7,864 W

450 T

125 P

92 H

COS Hydrolysis 1,013,462 W

367 T

580 P

289 H

1,013,462 W

367 T

590 P

289 H

10 11

19

Clean 

Gas

Acid 

Gas

13

AGR- MDEA

17

Tail Gas

Compressor

Hydrogenation

And Tail Gas

Cooling

388,450 W

150 T

1,205 P

117 H

388,450 W

337 T

595 P

326 H

From Fuel Gas 

Preheater

To Fuel Gas 

Preheater

249,929 W

From Gland Steam 

Condenser

To Syngas 

Cooling

113 T

53,768 W

120 T

57 P

33 H

To Preheater and 

LP Evaporator

From Tail Gas 

Cooler and LP 

Economizer

COS Hydrolysis

Preheater

From HP 

Economizer 2 To Superheater

To Water 

Treatment

Makeup Water

Reboiler

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas 

Scrubber and HP 

Economizer 1

Claus Oxygen

Preheater

To 

Deaerator

From IP 

BFW

Fuel Gas 

Preheater

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

Net Plant Heat Rate: 8,585 Btu/kWh

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

127

Exhibit 3-53 Case B4A combined cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4A

COP GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B4A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Condensate

Pumps

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,602,981 W

101 T

1 P

69 H

8,756,467 W

270 T

15 P

117 H

944,784 W

380 T

460 P

245 H

1,595,860 W

1,041 T

1,815 P

1,497 H

9,989 W

298 T

65 P

1,171 H

1,414,148 W

540 T

65 P

1,294 H

1,400 W

660 T

65 P

1,353 H

1,400 W

212 T

15 P

180 H

21

25

16

24

Hot Well

Condenser 176,911 W

59 T

15 P

27 H

8,829 W

700 T

501 P

1,350 H

9,522 W

660 T

65 P

1,353 H

1,313 W

540 T

65 P

1,294 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas Cooler

Blowdown 

Flash

Deaerator

LP 

Evaporator

From Claus, Process Extractions, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat

8,756,467 W

1,091 T

15 P

337 H

23

To WWT

Condensate to Tail 

Gas Cooling

Process 

Extraction

46,042 W

276 T

615 P

244 H

1,872,987 W

274 T

45 P

242 H

24,616 W

274 T

79 P

242 H

9,365 W

274 T

79 P

242 H

1,623,815 W

279 T

2,251 P

247 H

306,059 W

298 T

65 P

266 H

235 T 305 T 585 T 636 T

117,894 W

351 T

2,251 P

319 H

117,894 W

585 T

2,001 P

585 H

27,956 W

585 T

2,001 P

585 H

1,223,167 W

585 T

2,001 P

585 H

636 T

215,192 W

298 T

65 P

1,171 H

1,437,747 W

701 T

501 P

1,350 H

22

280,565 W

810 T

235 P

199 H

195 T

Process Extraction

14,000 W

540 T

65 P

1,294 H

1,078,115 W

385 T

389 P

87 H

Steam to Gasifier

149,578 W

690 T

745 P

1,328 H

LP Extraction 

Spray #2

19,510 W

241 T

825 P

209 H

Water Makeup

1,000 W

1,041 T

1,815 P

1,497 H

1,000 W

212 T

15 P

180 H

781 W

1,041 T

1,815 P

1,497 H 30,828 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

1,602,981 W

103 T

120 P

71 H

274 T

To Post 

Particulate 

and Syngas 

Coolers

From Post 

Particulate 

and Syngas 

Coolers

From ASU and Fuel 

Gas Preheater

To ASU and Fuel 

Gas Preheater

To Fire Tube Boiler 

and COS Preheater

From Fire Tube Boiler and COS 

Preheater

1,041 T

To Claus

Nitrogen Diluent

Fuel Gas

Air Extraction

Ambient Air

HP Pump

LP Pump

IP Pump

Gross Plant Power: 738 MWe

Auxiliary Load: 113 MWe

Net Plant Power: 625 MWe

Net Plant Efficiency, HHV: 39.7%

Net Plant Heat Rate: 8,585 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

128

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

129

Exhibit 3-54 Case B4A overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,661 

(5,366)

4.7 (4.5) – 5,666 

(5,370)

Air – 112.7 (106.8) – 112.7 

(106.8)

Raw Water Makeup – 62.4 (59.1) – 62.4 (59.1)

Auxiliary Power – – 408 (386) 408 (386)

TOTAL 5,661 

(5,366)

179.8 (170.4) 408 (386) 6,249 

(5,923)

Heat Out (GJ/hr)

ASU Vent – 0.9 (0.9) – 0.9 (0.9)

Slag 34.9 (33.1) 23.9 (22.7) – 58.8 (55.7)

Stack Gas – 1,082 (1,025) – 1,082 

(1,025)

Sulfur 48.3 (45.8) 0.6 (0.6) – 48.9 (46.4)

Motor Losses and Design 

Allowances

– – 52.3 (49.6) 52.3 (49.6)

Condenser – 1,415 (1,341) – 1,415 

(1,341)

Non-Condenser Cooling Tower 

Loads

– 445 (421) – 445 (421)

CO2 – – – –

Blowdown – 32.2 (30.5) – 32.2 (30.5)

CO2 Capture Losses – – – –

Ambient LossesA – 157.4 (149.2) – 157.4 

(149.2)

Power – – 2,658 

(2,519)

2,658 

(2,519)

TOTAL 83.2 (78.9) 3,157 (2,992) 2,710 

(2,568)

5,950 

(5,639)

Unaccounted EnergyB – 299 (283) – 299 (283)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

3.3.6 Case B4A - Major Equipment List

Major equipment items for the E-GasTM gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.3.7. In general, the design conditions include a 10 percent 

contingency for flows and heat duties, and a 21 percent contingency for heads on pumps and 

fans.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

130

Case B4A – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 340 tonne/hr (380 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 760 tonne (840 ton) 3 0

Case B4A – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (80 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/h (250 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 460 tonne (510 ton) 1 0

4 Weigh Feeder Belt 110 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 110 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with 

Agitator Field erected 283,240 liters (74,820 gal) 2 0

7 Slurry Water Pumps Centrifugal 790 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 160 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 370,530 liters (97,880 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,100 lpm (800 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,111,600 liters (293,600 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,200 lpm (1,600 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,100 lpm (800 gpm) 2 2

Case B4A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,083,000 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,710 lpm @ 90 m H2O

(1,770 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 479,000 kg/hr (1,055,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,100 lpm @ 30 m H2O

(2,140 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

7,020 lpm @ 1,800 m H2O 

(1,860 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal

IP water: 510 lpm @ 220 m 

H2O (130 gpm @ 730 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

131

Equipment 

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 245 GJ/hr (232 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 87,700 lpm @ 20 m H2O(23,200 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

4,240 lpm @ 20 m H2O

(1,120 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,830 lpm @ 270 m H2O 

(750 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

1,640 lpm @ 50 m H2O

(430 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 787,000 liter (208,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 300 lpm (80 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B4A – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2,800 tonne/day, 4.2 MPa

(3,000 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 310,000 kg/hr (683,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 310,000 kg/hr (683,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 265,000 kg/hr (584,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 213,000 kg/hr (469,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

212,000 kg/hr, 35°C, 3.9 MPa

(468,000 lb/hr, 95°F, 560 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 91 GJ/hr (86 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 236,000 kg/hr, 143°C, 3.3 MPa

(520,000 lb/hr, 290°F, 480 psia) 2 0

10 Saturator Water 

Pump Centrifugal 2,100 lpm @ 13 m H2O(600 gpm @ 42 ft H2O) 2 2

11 Synthesis Gas 

Reheater Shell and tube 209,000 kg/hr (461,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

265,000 kg/hr (584,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 4,000 m3/min @ 1.3 MPa(146,000 scfm @ 190 psia) 2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

132

Equipment 

No. Description Type Design Condition Operating Qty. Spares

14 Cold Box Vendor design 2,000 tonne/day (2,200 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (36,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

3,000 m3/min (119,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

470 m3/min (17,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18 Transport Nitrogen 

Boost Compressor

Centrifugal, singlestage

50 m3/min (2,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

19 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

70,000 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0

Case B4A – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 211,000 kg/hr (466,000 lb/hr),

35°C (95°F), 3.8 MPa (555 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 211,000 kg/hr (466,000 lb/hr),

35°C (95°F), 3.8 MPa (550 psia) 2 0

3 Sulfur Plant Claus type 138 tonne/day (152 tpd) 1 0

4 COS Hydrolysis 

Reactor Fixed bed, catalytic 253,000 kg/hr (557,000 lb/hr),188°C (370°F), 4.1 MPa (590 psia) 2 0

5 Acid Gas Removal 

Plant MDEA 225,000 kg/hr (495,000 lb/hr),34°C (94°F), 3.8 MPa (550 psia) 2 0

6 Hydrogenation 

Reactor Fixed bed, catalytic

31,000 kg/hr (68,000 lb/hr),

232°C (450°F), 0.4 MPa (58.9 

psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 26,000 kg/hr (58,000 lb/hr) each 1 0

Case B4A – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

Case B4A – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 398,129 kg/hr, 

12.4 MPa/561°C 

(877,723 lb/hr, 1,800 psig/1,041°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

133

Case B4A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

289 MW

12.4 MPa/561°C/561°C(1,800psig/ 

1,041°F/1,041°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,560GJ/hr (1,480 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B4A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 391,000 lpm @ 30 m(103,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,180 GJ/hr (2,060 MMBtu/hr) heat duty

1 0

Case B4A – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 223,000 liters (59,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (13 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (13 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 134,000 liters (36,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 61,000 liters (16,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (13 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (13 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (13 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 191,000 liters (50,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 61,000 liters (16,000 gal) 2 0

12 Grey Water Pumps Centrifugal 220 lpm @ 430 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 800 tonne (900 tons) 2 0

14 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

134

Case B4A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 290 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 47 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 29 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B4A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.3.7 Case B4A - Costs Estimating Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-55 shows a 

detailed breakdown of the capital costs; Exhibit 3-56 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-57 shows the initial and annual O&M costs; and Exhibit 3-58 shows the COE 

breakdown. 

The estimated TPC of the E-GasTM gasifier with no CO2 capture is $2,372/kW. Process 

contingency represents 2.6 percent of the TPC, and project contingency is 13.6 percent. The 

COE is $99.8/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

135

Exhibit 3-55 Case B4A total plant cost details

Case: B4A – E-GasTM IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,394 $0 $2,118 $0 $6,511 $651 $0 $1,433 $8,595 $14

1.2 Coal Stackout & Reclaim $5,678 $0 $1,358 $0 $7,035 $704 $0 $1,548 $9,287 $15

1.3 Coal Conveyors & Yd Crush $5,279 $0 $1,343 $0 $6,622 $662 $0 $1,457 $8,741 $14

1.4 Other Coal Handling $1,381 $0 $311 $0 $1,692 $169 $0 $372 $2,233 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $2,934 $7,668 $0 $10,602 $1,060 $0 $2,332 $13,994 $22

Subtotal $16,731 $2,934 $12,797 $0 $32,462 $3,246 $0 $7,142 $42,850 $69

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,872 $450 $290 $0 $2,612 $261 $0 $575 $3,447 $6

2.3 Slurry Prep & Feed $25,543 $0 $11,204 $0 $36,748 $3,675 $0 $8,084 $48,507 $78

2.4 Misc. Coal Prep & Feed $1,030 $752 $2,216 $0 $3,997 $400 $0 $879 $5,277 $8

2.9 Coal & Sorbent Feed Foundation $0 $3,777 $3,241 $0 $7,017 $702 $0 $1,544 $9,263 $15

Subtotal $28,445 $4,979 $16,950 $0 $50,374 $5,037 $0 $11,082 $66,494 $106

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,767 $6,501 $3,408 $0 $13,676 $1,368 $0 $3,009 $18,052 $29

3.2 Water Makeup & Pretreating $715 $74 $393 $0 $1,182 $118 $0 $390 $1,690 $3

3.3 Other Feedwater Subsystems $2,118 $700 $626 $0 $3,443 $344 $0 $757 $4,545 $7

3.4 Service Water Systems $418 $834 $2,874 $0 $4,125 $413 $0 $1,361 $5,899 $9

3.5 Other Boiler Plant Systems $2,253 $842 $2,072 $0 $5,167 $517 $0 $1,137 $6,821 $11

3.6 FO Supply Sys & Nat Gas $17,737 $713 $660 $0 $19,110 $1,911 $0 $4,204 $25,225 $40

3.7 Waste Treatment Equipment $967 $0 $599 $0 $1,566 $157 $0 $517 $2,240 $4

3.8 Misc. Power Plant Equipment $1,268 $169 $659 $0 $2,096 $210 $0 $692 $2,997 $5

Subtotal $29,243 $9,832 $11,290 $0 $50,365 $5,036 $0 $12,067 $67,468 $108

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $144,797 $0 $80,864 $0 $225,661 $22,566 $31,351 $42,853 $322,431 $516

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $174,614 $0 w/equip. $0 $174,614 $17,461 $0 $19,208 $211,284 $338

4.4 LT Heat Recovery & FG Saturation $20,488 $0 $7,784 $0 $28,273 $2,827 $0 $6,220 $37,320 $60

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,778 $719 $0 $2,496 $250 $0 $549 $3,295 $5

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,517 $5,676 $0 $15,193 $1,519 $0 $4,178 $20,891 $33

Subtotal $339,900 $11,295 $95,043 $0 $446,238 $44,624 $31,351 $73,008 $595,220 $952

5A Gas Cleanup & Piping

5A.1 MDEA-LT AGR System $42,958 $0 $36,202 $0 $79,161 $7,916 $0 $17,415 $104,492 $167

5A.2 Elemental Sulfur Plant $11,980 $2,335 $15,351 $0 $29,667 $2,967 $0 $6,527 $39,160 $63

5A.3 Mercury Removal $1,390 $0 $1,051 $0 $2,441 $244 $122 $562 $3,369 $5

5A.4 COS Hydrolysis $3,852 $0 $4,996 $0 $8,849 $885 $0 $1,947 $11,680 $19

5A.5 Particulate Removal w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

136

Case: B4A – E-GasTM IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.6 Blowback Gas Systems $601 $337 $188 $0 $1,127 $113 $0 $248 $1,487 $2

5A.7 Fuel Gas Piping $0 $984 $644 $0 $1,628 $163 $0 $358 $2,149 $3

5A.9 HGCU Foundations $0 $891 $600 $0 $1,491 $149 $0 $492 $2,132 $3

Subtotal $60,783 $4,547 $59,033 $0 $124,363 $12,436 $122 $27,548 $164,470 $263

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $7,506 $0 $111,706 $11,171 $5,585 $12,846 $141,308 $226

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $5

Subtotal $104,200 $923 $8,575 $0 $113,698 $11,370 $5,585 $13,504 $144,157 $231

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,180 $0 $6,038 $0 $37,218 $3,722 $0 $4,094 $45,034 $72

7.3 Ductwork $0 $2,084 $1,461 $0 $3,544 $354 $0 $780 $4,679 $7

7.4 Stack $4,021 $0 $1,500 $0 $5,522 $552 $0 $607 $6,681 $11

7.9 HRSG, Duct & Stack Foundations $0 $766 $768 $0 $1,534 $153 $0 $506 $2,194 $4

Subtotal $35,201 $2,849 $9,768 $0 $47,818 $4,782 $0 $5,987 $58,588 $94

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,955 $0 $5,943 $0 $44,898 $4,490 $0 $4,939 $54,326 $87

8.2 Turbine Plant Auxiliaries $242 $0 $551 $0 $793 $79 $0 $87 $960 $2

8.3 Condenser & Auxiliaries $3,140 $0 $1,774 $0 $4,914 $491 $0 $541 $5,946 $10

8.4 Steam Piping $16,507 $0 $7,158 $0 $23,665 $2,367 $0 $6,508 $32,540 $52

8.9 TG Foundations $0 $1,141 $2,015 $0 $3,156 $316 $0 $1,042 $4,513 $7

Subtotal $58,844 $1,141 $17,441 $0 $77,426 $7,743 $0 $13,116 $98,285 $157

9 Cooling Water System

9.1 Cooling Towers $3,980 $0 $1,210 $0 $5,190 $519 $0 $856 $6,565 $11

9.2 Circulating Water Pumps $1,923 $0 $137 $0 $2,060 $206 $0 $340 $2,605 $4

9.3 Circ. Water System Auxiliaries $170 $0 $24 $0 $194 $19 $0 $32 $246 $0

9.4 Circ. Water Piping $0 $7,546 $1,828 $0 $9,374 $937 $0 $2,062 $12,373 $20

9.5 Make-up Water System $408 $0 $560 $0 $968 $97 $0 $213 $1,278 $2

9.6 Component Cooling Water Sys $863 $1,032 $708 $0 $2,603 $260 $0 $573 $3,436 $5

9.9 Circ. Water System Foundations $0 $2,470 $4,389 $0 $6,859 $686 $0 $2,264 $9,809 $16

Subtotal $7,343 $11,048 $8,857 $0 $27,248 $2,725 $0 $6,340 $36,313 $58

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $20,022 $0 $9,806 $0 $29,828 $2,983 $0 $3,281 $36,092 $58

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $660 $0 $714 $0 $1,374 $137 $0 $227 $1,738 $3

10.7 Ash Transport & Feed Equipment $909 $0 $212 $0 $1,121 $112 $0 $185 $1,418 $2

10.8 Misc. Ash Handling Equipment $1,368 $1,676 $497 $0 $3,542 $354 $0 $584 $4,480 $7

10.9 Ash/Spent Sorbent Foundation $0 $55 $73 $0 $128 $13 $0 $42 $184 $0

Subtotal $22,959 $1,732 $11,302 $0 $35,994 $3,599 $0 $4,320 $43,913 $70

11 Accessory Electric Plant

11.1 Generator Equipment $1,156 $0 $1,126 $0 $2,282 $228 $0 $251 $2,761 $4

11.2 Station Service Equipment $4,391 $0 $404 $0 $4,795 $479 $0 $527 $5,802 $9
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

137

Case: B4A – E-GasTM IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 625 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.3 Switchgear & Motor Control $8,105 $0 $1,506 $0 $9,611 $961 $0 $1,586 $12,158 $19

11.4 Conduit & Cable Tray $0 $4,118 $12,694 $0 $16,812 $1,681 $0 $4,623 $23,116 $37

11.5 Wire & Cable $0 $7,940 $4,831 $0 $12,770 $1,277 $0 $3,512 $17,559 $28

11.6 Protective Equipment $0 $798 $2,961 $0 $3,759 $376 $0 $620 $4,755 $8

11.7 Standby Equipment $275 $0 $274 $0 $548 $55 $0 $90 $694 $1

11.8 Main Power Transformers $17,611 $0 $173 $0 $17,785 $1,778 $0 $2,934 $22,497 $36

11.9 Electrical Foundations $0 $181 $493 $0 $674 $67 $0 $223 $964 $2

Subtotal $31,538 $13,036 $24,462 $0 $69,036 $6,904 $0 $14,367 $90,306 $144

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,186 $0 $808 $0 $1,994 $199 $100 $344 $2,637 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $273 $0 $178 $0 $451 $45 $23 $104 $622 $1

12.7 Computer & Accessories $6,326 $0 $207 $0 $6,533 $653 $327 $751 $8,264 $13

12.8 Instrument Wiring & Tubing $0 $2,435 $4,610 $0 $7,045 $705 $352 $2,025 $10,127 $16

12.9 Other I & C Equipment $4,229 $0 $2,095 $0 $6,324 $632 $316 $1,091 $8,364 $13

Subtotal $12,014 $2,435 $7,898 $0 $22,347 $2,235 $1,117 $4,315 $30,014 $48

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,672 $0 $2,790 $279 $0 $921 $3,990 $6

13.2 Site Improvements $0 $2,090 $2,955 $0 $5,046 $505 $0 $1,665 $7,215 $12

13.3 Site Facilities $3,746 $0 $4,205 $0 $7,951 $795 $0 $2,624 $11,370 $18

Subtotal $3,746 $2,208 $9,833 $0 $15,787 $1,579 $0 $5,210 $22,575 $36

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,917 $4,153 $0 $7,069 $707 $0 $1,166 $8,943 $14

14.3 Administration Building $0 $1,008 $731 $0 $1,740 $174 $0 $287 $2,201 $4

14.4 Circulation Water Pumphouse $0 $199 $105 $0 $304 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $588 $573 $0 $1,161 $116 $0 $192 $1,468 $2

14.6 Machine Shop $0 $516 $353 $0 $869 $87 $0 $143 $1,099 $2

14.7 Warehouse $0 $833 $538 $0 $1,371 $137 $0 $226 $1,734 $3

14.8 Other Buildings & Structures $0 $499 $388 $0 $888 $89 $0 $195 $1,172 $2

14.9 Waste Treating Building & Str. $0 $1,116 $2,131 $0 $3,247 $325 $0 $714 $4,286 $7

Subtotal $0 $7,993 $9,151 $0 $17,144 $1,714 $0 $3,083 $21,942 $35

Total $750,947 $76,953 $302,400 $0 $1,130,300 $113,030 $38,175 $201,088 $1,482,594 $2,372
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-56 Case B4A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $14,793 $24

1 Month Maintenance Materials $3,377 $5

1 Month Non-fuel Consumables $399 $1

1 Month Waste Disposal $434 $1

25% of 1 Months Fuel Cost at 100% CF $2,877 $5

2% of TPC $29,652 $47

Total $51,532 $82

Inventory Capital

60-day supply of fuel and consumables at 100% CF $23,491 $38

0.5% of TPC (spare parts) $7,413 $12

Total $30,904 $49

Other Costs

Initial Cost for Catalyst and Chemicals $2,218 $4

Land $900 $1

Other Owner's Costs $222,389 $356

Financing Costs $40,030 $64

Total Overnight Costs (TOC) $1,830,567 $2,929

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,086,847 $3,339
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-57 Case B4A initial and annual operating and maintenance costs

Case: B4A – E-GasTM IGCC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 625 Heat Rate-net (Btu/kWh): 8,585 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 9.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 15.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $6,781,554 $10.851

Maintenance Labor: $16,886,458 $27.019

Administrative & Support Labor: $5,917,003 $9.467

Property Taxes and Insurance: $29,651,871 $47.444

Total: $59,236,887 $94.781

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $32,421,135 $7.40220

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,155 $1.67 $0 $1,542,265 $0.35212

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 18,798 $0.27 $0 $1,470,139 $0.33565

Carbon (Mercury Removal) (lb): 115,489 198 $5.50 $635,191 $317,595 $0.07251

COS Catalyst (m3): 327 0.22 $3,751.70 $1,227,074 $245,415 $0.05603

MDEA Solution (gal): 26,146 37 $13.62 $356,095 $146,323 $0.03341

Claus Catalyst (ft3): w/equip. 1.91 $203.15 $0 $113,350 $0.02588

Subtotal: $2,218,360 $3,835,086 $0.87560

Waste Disposal

Spent Mercury Catalyst (lb.): 0 198 $0.65 $0 $37,539 $0.00857

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 563 $25.11 $0 $4,130,607 $0.94308

 Subtotal: $0 $4,168,147 $0.95165

By-Products

Sulfur (tons): 0 138 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $2,218,360 $40,424,368 $9.22946

Fuel Cost

Illinois Number 6 (ton): 0 5,519 $68.54 $0 $110,464,984 $25.22072

Total: $0 $110,464,984 $25.22072

Exhibit 3-58 Case B4A COE breakdown

Component Value, $/MWh Percentage

Capital 51.8 52%

Fixed 13.5 14%

Variable 9.2 9%

Fuel 25.2 25%

Total (Excluding T&S) 99.8 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 99.8 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.3.8 Case B4B - E-GasTM IGCC Power Plant with CO2 Capture

This case is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case B4A, namely two gasifier trains, two state-of-the-art 2008 F-class turbines, two 

HRSGs, and one steam turbine. The gross power output from the plant is constrained by the 

capacity of the two CTs, and since the CO2 capture and compression process increases the 

auxiliary load on the plant, the net output is significantly reduced relative to Case B4A.

The process description for Case B4B is similar to Case B4A with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case B4B are shown in Exhibit 3-59

and Exhibit 3-60, respectively. Instead of repeating the entire process description, only 

differences from Case B4A are reported here.

3.3.8.1 Coal Preparation and Feed Systems

No differences from Case B4A.

3.3.8.2 Gasification

The gasification process is the same as Case B4A with the exception that total coal feed to the 

two gasifiers is 5,271 tonnes/day (5,811 tpd) (stream 8) and the ASU provides 4,234 tonnes/day 

(4,668 tpd) of 95 mol% oxygen to the gasifier and Claus plant (streams 5 and 3).

3.3.8.3 Raw Gas Cooling/Particulate Removal

Raw gas cooling and particulate removal are the same as Case B4A with the exception that 

approximately 418,710 kg/hr (923,082 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the SGC.

3.3.8.4 Syngas Scrubber/Sour Water Stripper

No differences from Case B4A.

3.3.8.5 Sour Gas Shift

The SGS process was described in Section 3.1.3. In Case B4B steam (stream 11) is added to the 

syngas exiting the scrubber to adjust the H2O:CO molar ratio to approximately 2.25:1 prior to the 

first SGS reactor. The hot syngas exiting the first stage of SGS is used to preheat a portion of the 

water used to humidify the clean syngas leaving the AGR. The final stage of SGS brings the 

overall conversion of the CO to CO2 to 98.5 percent. The syngas exiting the final stage of SGS 

still contains 1.2 vol% CH4, which is subsequently oxidized to CO2 in the CT and results in a 

carbon capture of 89.9 percent. The warm syngas exiting the second stage of the SGS at 204°C 

(400°F) (stream 12) is cooled to 201°C (393°F) by preheating the syngas entering the first SGS 

reactor. The SGS catalyst also serves to hydrolyze COS thus eliminating the need for a separate 

COS hydrolysis reactor. The syngas is further dehydrated and cooled to 35°C (95°F) in syngas 

coolers prior to the mercury removal beds.

3.3.8.6 Mercury Removal and Acid Gas Removal

Mercury removal is the same as in Case B4A.

The AGR process in Case B4B is a two-stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption, as previously described in Section 3.1.5. The 

process results in three product streams: the clean syngas, a CO2-rich stream, and an acid gas 

feed to the Claus plant. The acid gas (stream 19) contains 21.5 percent H2S and 70 percent CO2
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

141

with the balance primarily H2. The CO2-rich stream is discussed further in the CO2 compression 

section.

3.3.8.7 CO2 Compression and Dehydration

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

1.0 MPa (149.5 psia) to an SC condition at 15.3 MPa (2215 psia) using a multiple-stage, 

intercooled compressor. During compression, the CO2 stream is dehydrated to a dew point

of -40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 18) is transported to the plant fence line and is 

sequestration ready. CO2 T&S costs were estimated using the methodology described in 

Section 2.6.

3.3.8.8 Claus Unit

The Claus plant is the same as Case B4A with the following exceptions:

• 5,494 kg/hr (12,112 lb/hr) of sulfur (stream 20) are produced

• The waste heat boiler generates 12,679 kg/hr (27,953 lb/hr) of 3.0 MPa (430 psia) steam, 

which provides all of the Claus plant process needs and provides some additional steam 

to the medium pressure steam header

3.3.8.9 Power Block

Clean syngas from the AGR plant is partially humidified to 4 percent because the nitrogen 

available from the ASU is insufficient to provide adequate dilution. The moisturized syngas is 

reheated (stream 17) to 193°C (380°F) using HP BFW, diluted with nitrogen (stream 4), and then 

enters the CT burner. There is no integration between the CT and the ASU in this case. The 

exhaust gas (stream 23) exits the CT at 562°C (1044°F) and enters the HRSG where additional 

heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 24) and is discharged 

through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1,800 psig/994°F/994°F) 

steam cycle.

3.3.8.10 Air Separation Unit (ASU)

The elevated pressure ASU is the same as in other cases and produces 4,234 tonnes/day (4,668 

tpd) of 95 mol% oxygen and 14,230 tonnes/day (15,686 tpd) of nitrogen. There is no integration 

between the ASU and the CT for the CO2 capture case.

3.3.8.11 Balance of Plant

Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.12.
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Exhibit 3-59 Case B4B block flow diagram, E-GasTM IGCC with CO2 capture

Source: NETL

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

SHIFT

REACTORS

ELEVATED

PRESSURE ASU

E-GASTM

GASIFIER

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

DUAL

STAGE

SELEXOL

UNIT

CLAUS

PLANT

HRSG

AMBIENT AIR

HYDROGENATION

REACTOR AND GAS

COOLER

GAS

TURBINE

COMBUSTOR

TURBINE COOLING AIR

SYNGAS

COOLING, 

CYCLONES & 

FILTERS

CO2

COMPRESSION

1

5

11

12 13

17

19

20

18

8 10

2 3

4

22

23 24

AIR TO ASU

AS-RECEIVED

COAL

SLAG

SHIFT

STEAM

WATER RECYCLE

TO SLURRY

PREPARATION

NITROGEN DILUENT

SYNGAS

CLEAN

GAS

CO2

STREAMS

CO2

PRODUCT

SULFUR

TAIL GAS

RECYCLE TO

SELEXOL

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

FLUE GAS

STACK GAS

VENT GAS

14

SYNGAS

REHEATER

NOTE: SYNGAS RECYCLE

MODELED, BUT NOT SHOWN

GASIFIER

OXIDANT

RECYCLE TO

GASIFIER

OUTLET

2X STATE-OF-THEART F-CLASS

GAS TURBINES

CLAUS

PLANT

OXIDANT

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

25

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

SLURRY

MIXER

9

SLURRY

WATER

21

TAIL GAS

RECYCLE FROM

CLAUS PLANT

6

7

SOUR WATER

STEAM

SYNGAS

HUMIDIFICATION

15

16
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Exhibit 3-60 Case B4B stream table, E-GasTM IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0209 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0054 0.0071 0.0071

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0125 0.0164 0.0159

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0028 0.0037 0.0038

CO2 0.0003 0.0071 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3103 0.4090 0.4172

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.4128 0.5441 0.5341

H2O 0.0099 0.1780 0.0000 0.0003 0.0000 1.0000 1.0000 0.0000 0.9963 0.0000 1.0000 0.2376 0.0015 0.0015

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0048 0.0063 0.0062

N2 0.7732 0.6187 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0090 0.0119 0.0142

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0037 0.0000 0.0000 0.0046 0.0000 0.0000

O2 0.2074 0.1754 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 26,685 1,231 145 19,704 5,338 1,287 4,969 0 5,009 0 9,357 37,866 26,948 27,761

V-L Flowrate (kg/hr) 770,042 33,603 4,654 552,893 171,782 23,193 89,523 0 90,226 0 168,565 748,369 547,649 575,208

Solids Flowrate (kg/hr) 0 0 0 0 0 0 0 219,635 0 22,418 0 0 0 0

Temperature (°C) 15 19 32 93 32 154 343 15 171 1,038 288 204 35 34

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 5.79 5.10 0.10 5.79 4.24 5.52 4.07 3.79 3.76

Steam Table Enthalpy (kJ/kg) A 30.23 36.49 26.67 92.50 26.67 646.63 3,062.93 --- 673.50 --- 2,917.15 874.40 40.91 39.04

AspenPlus Enthalpy (kJ/kg)B -97.58 -1,964.01 4.13 63.47 4.13 -15,372.01 -12,907.38 -2,116.95 -15,251.86 1,005.43 -13,053.16 -8,872.57 -8,024.73 -8,027.16

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 857.7 20.1 --- 836.0 --- 25.6 20.6 30.9 31.3

V-L Molecular Weight 28.857 27.295 32.181 28.060 32.181 18.015 18.015 --- 18.012 --- 18.015 19.764 20.322 20.720

V-L Flowrate (lbmole/hr) 58,830 2,714 319 43,440 11,768 2,838 10,955 0 11,044 0 20,628 83,479 59,411 61,202

V-L Flowrate (lb/hr) 1,697,652 74,082 10,260 1,218,920 378,715 51,133 197,365 0 198,914 0 371,622 1,649,872 1,207,359 1,268,117

Solids Flowrate (lb/hr) 0 0 0 0 0 0 0 484,212 0 49,422 0 0 0 0

Temperature (°F) 59 67 90 199 90 310 650 59 340 1,900 550 400 95 94

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 840.0 740.0 14.7 840.0 615.0 800.0 590.0 550.0 545.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.7 11.5 39.8 11.5 278.0 1,316.8 --- 289.6 --- 1,254.1 375.9 17.6 16.8

AspenPlus Enthalpy (Btu/lb)B -42.0 -844.4 1.8 27.3 1.8 -6,608.8 -5,549.2 -910.1 -6,557.1 432.3 -5,611.9 -3,814.5 -3,450.0 -3,451.1

Density (lb/ft3) 0.076 0.095 0.687 1.521 0.687 53.543 1.257 --- 52.192 --- 1.597 1.285 1.928 1.953

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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Exhibit 3-60 Case B4B stream table, E-GasTM IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0119 0.0114 0.0114 0.0002 0.0011 0.0000 0.0068 0.0092 0.0090 0.0090 0.0000

CH4 0.0262 0.0251 0.0251 0.0008 0.0045 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0063 0.0060 0.0060 0.0001 0.0007 0.0000 0.0076 0.0000 0.0000 0.0000 0.0000

CO2 0.0352 0.0338 0.0338 0.9945 0.7021 0.0000 0.6907 0.0003 0.0082 0.0082 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.8964 0.8588 0.8588 0.0044 0.0591 0.0000 0.2007 0.0000 0.0000 0.0000 0.0000

H2O 0.0001 0.0421 0.0421 0.0000 0.0162 0.0000 0.0017 0.0099 0.1246 0.1246 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.2153 0.0000 0.0026 0.0000 0.0000 0.0000 0.0000

N2 0.0239 0.0229 0.0229 0.0001 0.0010 0.0000 0.0901 0.7732 0.7529 0.7529 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1052 0.1052 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 16,435 17,155 17,155 10,499 800 0 812 110,253 139,694 139,694 34,515

V-L Flowrate (kg/hr) 83,813 96,780 96,780 459,855 31,069 0 27,560 3,181,557 3,831,230 3,831,230 621,792

Solids Flowrate (kg/hr) 0 0 0 0 0 5,494 0 0 0 0 0

Temperature (°C) 34 108 193 51 48 176 38 15 562 132 534

Pressure (MPa, abs) 3.76 3.21 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 196.11 903.06 1,360.50 -162.35 62.13 --- 1.77 30.23 839.77 348.19 3,432.70

AspenPlus Enthalpy (kJ/kg)B -3,190.25 -4,169.46 -3,712.02 -9,119.38 -7,323.59 140.70 -8,075.42 -97.58 -608.99 -1,100.57 -12,537.61

Density (kg/m3) 7.4 5.6 4.6 641.8 2.4 5,283.7 83.6 1.2 0.4 0.9 36.7

V-L Molecular Weight 5.100 5.642 5.642 43.800 38.814 --- 33.925 28.857 27.426 27.426 18.015

V-L Flowrate (lbmole/hr) 36,233 37,820 37,820 23,146 1,765 0 1,791 243,066 307,972 307,972 76,092

V-L Flowrate (lb/hr) 184,776 213,363 213,363 1,013,808 68,496 0 60,759 7,014,133 8,446,417 8,446,417 1,370,817

Solids Flowrate (lb/hr) 0 0 0 0 0 12,112 0 0 0 0 0

Temperature (°F) 94 227 380 124 119 349 100 59 1,044 270 994

Pressure (psia) 545.0 465.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 84.3 388.2 584.9 -69.8 26.7 --- 0.8 13.0 361.0 149.7 1,475.8

AspenPlus Enthalpy (Btu/lb)B -1,371.6 -1,792.5 -1,595.9 -3,920.6 -3,148.6 60.5 -3,471.8 -42.0 -261.8 -473.2 -5,390.2

Density (lb/ft3) 0.461 0.352 0.285 40.067 0.149 329.851 5.220 0.076 0.026 0.053 2.293

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.3.9 Case B4B - Performance Results

The Case B4B modeling assumptions were presented previously in Section 3.3.3.

The plant produces a net output of 513 MWe at a net plant efficiency of 31.0 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-61; Exhibit 3-62

provides a detailed breakdown of the auxiliary power requirements. The ASU accounts for 

nearly 58 percent of the auxiliary load between the main air compressor, nitrogen compressor, 

oxygen compressor, and ASU auxiliaries. The two-stage Selexol process and CO2 compression 

account for an additional 27 percent of the auxiliary power load. The BFW pumps and cooling 

water system (CWPs and cooling tower fan) compose nearly 6 percent of the load, leaving 9 

percent of the auxiliary load for all other systems.

Exhibit 3-61 Case B4B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 240

Total Gross Power, MWe 704

Air Separation Unit Main Air Compressor, kWe 65,670

Oxygen Compressor, kWe 9,010

Nitrogen Compressors, kWe 35,340

CO2 Compression, kWe 31,380

Acid Gas Removal, kWe 19,900

Balance of Plant, kWe 28,950

Total Auxiliaries, MWe 190

Net Power, MWe 513

HHV Net Plant Efficiency (%) 31.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,607 (11,002)

HHV Cold Gas Efficiency, % 81.0%

HHV Combustion Turbine Efficiency, % 36.1%

LHV Net Plant Efficiency (%) 32.2%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,195 (10,611)

LHV Cold Gas Efficiency, % 76.9%

LHV Combustion Turbine Efficiency, % 42.4%

Steam Turbine Cycle Efficiency, % 41.5%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,668 (8,216)

Condenser Duty, GJ/hr (MMBtu/hr) 1,408 (1,334)

As-Received Coal Feed, kg/hr (lb/hr) 219,635 (484,212)

HHV Thermal Input, kWt 1,655,503

LHV Thermal Input, kWt 1,596,753

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.042 (11.2)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.034 (9.1)

O2:Coal 0.739
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Exhibit 3-62 Case B4B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 0

Steam Turbine Power, MWe 240

Total Gross Power, MWe 704

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,260

Sour Water Recycle Slurry Pump, kWe 200

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 65,670

Oxygen Compressor, kWe 9,010

Nitrogen Compressors, kWe 35,340

Feedwater Pumps, kWe 4,160

Quench Water Pump, kWe 0

Syngas Recycle Compressor, kWe 520

CO2 Compression, kWe 31,380

Scrubber Pumps, kWe 400

Acid Gas Removal, kWe 19,900

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 310

Circulating Water Pumps, kWe 4,700

Ground Water Pumps, kWe 520

Cooling Tower Fans, kWe 2,430

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 3,700

Miscellaneous Balance of PlantA, kWe 3,000

Transformer Losses, kWe 2,770

Total Auxiliaries, MWe 190

Net Power, MWe 513

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.3.9.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, CO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case B4B is presented in Exhibit 3-63. 

All HCl is assumed to be removed and is, therefore, not reported.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

147

Exhibit 3-63 Case B4B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.001 (0.002) 39 (43) 0.008 (0.017)

NOx 0.021 (0.049) 885 (976) 0.180 (0.396)

Particulates 0.003 (0.0071) 127 (141) 0.026 (0.057)

Hg 1.61E-7 (3.74E-7) 0.007 (0.007) 1.36E-6 (3.00E-6)

CO2 8 (20) 354,267 (390,512) 72 (158)

CO2C - - 98 (217)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the two-stage 

Selexol AGR process. The CO2 capture target results in the sulfur compounds being removed to 

a greater extent than required in the environmental targets of Section 2.3. The clean syngas 

exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This results in a 

concentration in the flue gas of less than 1 ppmv. The H2S-rich regeneration gas from the AGR 

system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail gas is 

hydrogenated to convert all sulfur species to H2S, and then recycled back to the Selexol, thereby 

eliminating the need for a tail gas treatment unit.

NOx emissions are limited by the use of humidification and nitrogen dilution to 15 ppmvd (NO2

@ 15 percent O2). Ammonia in the syngas is removed with process condensate prior to the lowtemperature AGR process and ultimately destroyed in the Claus plant burner. This helps lower 

NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of a cyclone 

and a barrier filter in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

Ninety five percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall carbon 

removal is 89.9 percent.

The carbon balance for the plant is shown in Exhibit 3-64. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as unburned carbon 

in the slag and as CO2 in the stack gas, ASU vent gas, and the captured CO2 product. The carbon 

capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the 

total carbon in less carbon contained in the slag, represented by the following fraction: 

CCCCCCCCCC SS

(TT TT CCCCCCCCCC ) − (CCCCCCCCCC SS SS) = �1 − � 30,416

309,844 − 2,469� ∗� 100 = 89.9%
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

148

The high methane content of the syngas, relative to the GEE and Shell cases, prevented reaching 

the nominal 90 percent carbon capture. In order to achieve 90 percent capture, the two-stage 

Selexol CO2 removal efficiency was increased from 92 to 95 percent. 

Exhibit 3-64 Case B4B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,006 (308,659) Stack Gas 13,796 (30,416)

Air (CO2) 537 (1,185) CO2 Product 125,522 (276,728)

ASU Vent 105 (231)

Slag 1,120 (2,469)

140,543 (309,844) Total 140,543 (309,844)

Exhibit 3-65 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur emitted in the 

stack gas, and sulfur in the CO2 product. Sulfur in the slag is considered to be negligible.

Exhibit 3-65 Case B4B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,505 (12,136) Stack Gas 3 (6)

CO2 Product 8 (18)

Elemental Sulfur 5,494 (12,112)

Total 5,505 (12,136) Total 5,505 (12,136)

Exhibit 3-66 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner for cases B1A through B4A.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

149

Exhibit 3-66 Case B4B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.49 (128) 0.49 (128) – – –

Slurry Water 1.51 (398) 1.51 (398) – – –

Quench/Wash – 0.00 () – – –

Humidifier 0.23 (61) 0.23 (61) – – –

SWS Blowdown – – – 0.03 (6.78) -0.03 (-6.78)

Condenser Makeup 4.52 (1,193) – 4.52 (1,193) – 4.52 (1,193)

 BFW Makeup 0.21 (55) – 0.21 (55) – 0.21 (55)

 Gasifier Steam 1.49 (395) – 1.49 (395) – 1.49 (395)

 Shift Steam 2.81 (743) – 2.81 (743) – 2.81 (743)

 CT Steam Dilution – – – – –

Cooling Tower 18.32 

(4,839) 1.04 (274) 17.28 (4,565) 4.12 (1,088) 13.16 (3,476)

 BFW Blowdown – 0.21 (55) -0.21 (-55) – -0.21 (-55)

 SWS Blowdown – 0.26 (67.78) -0.26 (-

67.78) – -0.26 (-67.78)

Total 25.05 

(6,618) 3.26 (861) 21.79 (5,757) 4.14 (1,095) 17.65 (4,662)

3.3.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-67 through 

Exhibit 3-69:

• Coal gasification and ASU

• Syngas cleanup including sulfur recovery and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-70. The power out is 

the combined CT and steam turbine power prior to generator losses. The power at the generator 

terminals (shown in Exhibit 3-61) is calculated by multiplying the power out by a combined 

generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

150

Exhibit 3-67 Case B4B coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4B

COP GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-B4B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

1,697,652 W

59 T

15 P

13 H

378,715 W

90 T

125 P

11 H

378,715 W

223 T

740 P

38 H

To Claus Plant

10,260 W

90 T

125 P

11 H

74,082 W

67 T

16 P

16 H

1,080,178 W

90 T

56 P

14 H

152,901 W

50 T

182 P

3 H

5

1

3

2

457,753 W

385 T

469 P

87 H

Candle Filter

Slurry Mix 

Tank

E-Gas TM

Gasifier

Slag

Cyclones

Syngas Recycle

Fire

Tube

Boiler

484,212 W

59 T

15 P

198,914 W

340 T

840 P

290 H

49,422 W

1,900 T

615 P

1,355,003 W

600 T

605 P

486 H

761,167 W

385 T

384 P

87 H

10

683,126 W

179 T

840 P

1,355,003 W

600 T

605 P

486 H

1,355,003 W

1,802 T

615 P

1,029 H

Boost Compressor

79,928 W

161 T

800 P

43 H

1,355,003 W

450 T

600 P

423 H

1,696,136 W

100 T

190 P

18 H

8

9

7

6 197,365 W

650 T

740 P

1,309 H

51,133 W

310 T

840 P

278 H

Syngas Recycle

Compressor

79,928 W

105 T

585 P

22 H

From LP

Economizer

To LP

Evaporator

To Superheater

From HP 

Economizer 2

Post 

Particulate 

Cooler

Raw 

Syngas 

to Scrubber

From HP 

Economizer 2

To HP Economizer 1

N2 to GT Combustor

N2 to GT Combustor

14,159 W

387 T

815 P

87 H

Boost 

Compressor

4

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 513 MWe

Net Plant Efficiency, HHV: 31.0%

Net Plant Heat Rate: 11,002 Btu/kWh

Sour Water

Steam

Water

Milled Coal

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

151

Exhibit 3-68 Case B4B syngas cleanup heat and mass balance schematic

Source: NETL

Mercury 

Removal

Knock

Out 

Drum

Multistage 

Intercooled CO2

Compressor

Raw Syngas

Humidified Fuel Gas

Sour

Drum

To Coal Slurrry and Slag Quench

Interstage Knockout

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

High

Temperature

Shift #1

Low 

Temperature 

Shift #2

Knock Out

Shift Steam

Syngas

Coolers

Sour

Stripper

Two-Stage

Selexol

Clean 

Gas

CO2

Acid 

Gas

Syngas

Scrubber

371,622 W

550 T

800 P

1,246 H

1,278,250 W

363 T

590 P

340 H

1,355,003 W

450 T

600 P

423 H

1,278,250 W

353 T

595 P

344 H

1,268,117 W

94 T

545 P

17 H

213,363 W

227 T

465 P

388 H

68,496 W

119 T

24 P

27 H

1,013,808 W

124 T

2,215 P

-70 H

1,547,580 W

393 T

585 P

372 H

213,363 W

380 T

460 P

585 H

12,112 W

72,809 W

280 T

17 P

313 H

6,165 W

195 T

65 P

206 H

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4B

COP GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-B4B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

2 OF 3

1,649,872 W

398 T

590 P

546 H

1,649,872 W

400 T

590 P

398 H

15

20

19

18

14

13

12

17

21

72,809 W

550 T

11 P

333 H

1,207,359 W

95 T

550 P

18 H

12,050 W

112 T

11 P

37 H

3

Syngas Recycle

11

60,759 W

100 T

800 P

1 H

1,649,872 W

400 T

590 P

376 H

1,649,872 W

698 T

590 P

533 H

102,292 W

393 T

585 P

372 H

Humidification 16

184,776 W

94 T

545 P

84 H

Tail Gas

Compressor

Hydrogenation

And Tail Gas

Cooling

469,170 W

353 T

595 P

347 H

469,170 W

150 T

1,205 P

116 H

To Fuel Gas 

Preheater

From Fuel 

Gas Preheater

338,892 W

To Water 

Treatment

Makeup Water

Reboiler

10,260 W

90 T

125 P

11 H

10,260 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To 

Deaerator

From IP 

BFW

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas 

Scrubber and HP 

Economizer 1

From IP BFW, LP 

BFW, and Tail 

Gas Cooling

To LP Turbine, Preheater

WGS/Gasifier Steam 

and Reheater 

Fuel Gas 

Humidification

CO2 Product

From Gland Steam 

Condenser To Syngas 

Cooling

111 T

Fuel Gas 

Preheater

COS 

Hydrolysis 

Preheater

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 513 MWe

Net Plant Efficiency, HHV: 31.0%

Net Plant Heat Rate: 11,002 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

152

Exhibit 3-69 Case B4B combined cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B4B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B4B

COP GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B4B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Condensate

Pumps

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

2,068,815 W

101 T

1 P

69 H

8,446,417 W

270 T

15 P

150 H

213,363 W

380 T

460 P

585 H

1,370,817 W

994 T

1,815 P

1,468 H

9,744 W

298 T

65 P

1,171 H

1,460,272 W

465 T

65 P

1,257 H

1,400 W

615 T

65 P

1,331 H

1,400 W

212 T

15 P

180 H

21

25

16

24

Hot Well

Condenser 596,381 W

59 T

15 P

27 H

9,026 W

660 T

501 P

1,327 H

9,762 W

615 T

65 P

1,331 H

1,337 W

505 T

65 P

1,277 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas Cooler

Blowdown 

Flash

Deaerator

LP 

Evaporator

From Claus, Process Extractions, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat

8,446,417 W

1,044 T

15 P

361 H

23

To WWT

Condensate to Tail 

Gas Cooling

Process 

1,973,163 W Extraction

274 T

45 P

242 H

26,434 W

274 T

79 P

242 H

9,866 W

274 T

79 P

242 H

1,398,140 W

279 T

2,251 P

247 H

353,694 W

298 T

65 P

266 H

235 T 305 T 585 T 636 T

300,993 W

351 T

2,251 P

319 H

300,993 W

585 T

2,001 P

585 H

27,273 W

585 T

2,001 P

585 H

923,082 W

585 T

2,001 P

585 H

636 T

265,292 W

298 T

65 P

1,171 H

1,195,395 W

661 T

501 P

1,327 H

205 T

761,167 W

385 T

469 P

87 H

Steam to Gasifier

168,786 W

650 T

740 P

1,303 H

LP Extraction 

Spray #2

22,016 W

241 T

825 P

209 H

Water Makeup

1,000 W

994 T

1,815 P

1,468 H

1,000 W

212 T

15 P

180 H

798 W

994 T

1,815 P

1,468 H 29,461 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

2,068,815 W

103 T

120 P

71 H

274 T

To Post 

Particulate 

Cooler

From Post 

Particulate 

Cooler

From ASU and Fuel 

Gas Preheater

To ASU and Fuel 

Gas Preheater

To Fire Tube Boiler

From Fire Tube Boiler

994 T

Nitrogen Diluent

Fuel Gas

Ambient Air

LP Pump

HP Pump

IP Pump

IP From Syngas and Pre 

Particulate Cooler

WGS Shift Steam

Cold Reheat

261,370 W

550 T

600 P

1,247 H

400,181 W

550 T

600 P

1,247 H

0 W

138,811 W

550 T

600 P

1,247 H

Gasifier Steam

LP To Syngas 

Coolers

264,385 W

274 T

79 P

242 H

LP From 

Syngas Coolers

264,385 W

298 T

65 P

1,171 H

IP to Pre Particulate 

and Syngas Coolers

58,909 W

276 T

615 P

244 H

400,181 W

275 T

615 P

243 H

IP To Claus

Gross Plant Power: 704 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 513 MWe

Net Plant Efficiency, HHV: 31.0%

Net Plant Heat Rate: 11,002 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

153

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

154

Exhibit 3-70 Case B4B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,960 

(5,649)

5.0 (4.7) – 5,965 

(5,654)

Air – 119.4 (113.2) – 119.4 

(113.2)

Raw Water Makeup – 81.9 (77.7) – 81.9 (77.7)

Auxiliary Power – – 685 (649) 685 (649)

TOTAL 5,960 

(5,649)

206.4 (195.6) 685 (649) 6,851 

(6,494)

Heat Out (GJ/hr)

ASU Vent – 1.2 (1.2) – 1.2 (1.2)

Slag 36.7 (34.8) 25.2 (23.9) – 61.9 (58.7)

Stack Gas – 1,334 (1,264) – 1,334 

(1,264)

Sulfur 50.9 (48.3) 0.6 (0.6) – 51.5 (48.8)

Motor Losses and Design 

Allowances – – 58.6 (55.6) 58.6 (55.6)

Condenser – 1,408 (1,334) – 1,408 

(1,334)

Non-Condenser Cooling Tower 

Loads – 801 (760) – 801 (760)

CO2 – -74.7 (-70.8) – -74.7 (-70.8)

Blowdown – 42.7 (40.5) – 42.7 (40.5)

CO2 Capture Losses – 182.6 (173.0) – 182.6 

(173.0)

Ambient LossesA – 168.2 (159.5) – 168.2 

(159.5)

Power – – 2,533 

(2,401)

2,533 

(2,401)

TOTAL 87.6 (83.1) 3,889 (3,686) 2,592 

(2,457)

6,569 

(6,226)

Unaccounted EnergyB – 282 (268) – 282 (268)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

3.3.10 Case B4B - Major Equipment List

Major equipment items for the E-GasTM gasifier with CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 

cost estimates in Section 3.3.11. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

155

Case B4B – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 800 tonne (900 ton) 3 0

Case B4B – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 480 tonne (530 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with 

Agitator Field erected 298,180 liters (78,770 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 390,070 liters(103,040 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,170,200 liters(309,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,300 lpm (900 gpm) 2 2

Case B4B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,100,000 liters (291,000 gal) 2 0

2 Condensate Pumps Vertical canned 8,660 lpm @ 90 m H2O

(2,290 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 607,000 kg/hr (1,338,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,540 lpm @ 30 m H2O

(2,260 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

6,050 lpm @ 1,800 m H2O

(1,600 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal

IP water: 1,300 lpm @ 220 m 

H2O (340 gpm @ 730 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

156

Equipment 

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 441 GJ/hr(418 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 158,100 lpm @ 20 m H2O(41,800 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

5,660 lpm @ 20 m H2O

(1,490 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,830 lpm @ 270 m H2O 

(750 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

3,070 lpm @ 50 m H2O

(810 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,471,000 liter (389,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 1,850 lpm (490 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B4B – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier

Pressurized two-stage, 

slurry-feed entrained 

bed

2,900 tonne/day, 4.2 MPa

(3,200 tpd, 615 psia) 2 0

2 Synthesis Gas Cooler Fire-tube boiler 338,000 kg/hr (745,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 338,000 kg/hr (745,000 lb/hr) Design efficiency 90% 2 0

4 Candle Filter Pressurized filter with 

pulse-jet cleaning metallic filters 2 0

5

Syngas Scrubber 

Including Sour Water 

Stripper

Vertical upflow 338,000 kg/hr (745,000 lb/hr) 2 0

6 Raw Gas Coolers Shell and tube with 

condensate drain 386,000 kg/hr (851,000 lb/hr) 8 0

7 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

303,000 kg/hr, 35°C, 3.8 MPa

(668,000 lb/hr, 95°F, 555 psia) 2 0

8 Saturation Water 

Economizers Shell and tube 36 GJ/hr (34 MMBtu/hr) 2 0

9 Fuel Gas Saturator Vertical tray tower 53,000 kg/hr, 108°C, 3.8 MPa

(117,000 lb/hr, 227°F, 545 psia) 2 0

10 Saturator Water 

Pump Centrifugal 700 lpm @ 13 m H2O(200 gpm @ 42 ft H2O) 2 2

11 Synthesis Gas 

Reheater Shell and tube 53,000 kg/hr (117,000 lb/hr) 2 0

12 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

338,000 kg/hr (745,000 lb/hr) 

syngas

2 0

13 ASU Main Air 

Compressor Centrifugal, multi-stage 6,000 m3/min @ 1.3 MPa(205,000 scfm @ 190 psia) 2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Equipment 

No. Description Type Design Condition Operating Qty. Spares

14 Cold Box Vendor design 2,300 tonne/day (2,600 tpd) of 

95% purity oxygen 2 0

15 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (41,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 5.1 MPa (740 psia)

2 0

16 Primary Nitrogen 

Compressor Centrifugal, multi-stage

4,000 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

17 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

540 m3/min (19,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

18

Gasifier Purge 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

2,000 m3/min (57,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0

Case B4B – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 301,000 kg/hr (664,000 lb/hr),

35°C (95°F), 3.8 MPa (550 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 301,000 kg/hr (664,000 lb/hr),

35°C (95°F), 3.8 MPa (550 psia) 2 0

3 Sulfur Plant Claus type 145 tonne/day (160 tpd) 1 0

4 Water Gas Shift 

Reactors Fixed bed, catalytic 206,000 kg/hr (454,000 lb/hr),204°C (400°F), 4.1 MPa (590 psia) 4 0

5

Shift Reactor Heat 

Recovery 

Exchangers

Shell and Tube

Exchanger 1: 94 GJ/hr (89

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

4 0

6 Acid Gas Removal 

Plant Two-stage Selexol 316,000 kg/hr (697,000 lb/hr),34°C (94°F), 3.8 MPa (545 psia) 2 0

7 Hydrogenation 

Reactor Fixed bed, catalytic

36,000 kg/hr (80,000 lb/hr),

232°C (450°F), 0.1 MPa (12.3

psia)

1 0

8 Tail Gas Recycle 

Compressor Centrifugal 30,000 kg/hr (67,000 lb/hr) each 1 0

9 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

1,100 m3/min @ 15.3 MPa (40,300 

scfm @ 2,215 psia) 4 0

Case B4B – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

Case B4B – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 409SS 

liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multi-pressure 

with economizer section

and integral deaerator

Main steam - 341,986 kg/hr, 

12.4 MPa/534°C 

(753,949 lb/hr, 1,800 psig/994°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case B4B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

252 MW

12.4 MPa/534°C/534°C (1,800 psig/ 

994°F/994°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

280 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,550GJ/hr (1,470 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B4B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 472,000 lpm @ 30 m(125,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,630 GJ/hr (2,490 MMBtu/hr) heat duty

1 0

Case B4B – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 235,000 liters (62,000 gal) 2 0

2 Slag Crusher Roll 12 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Proprietary 12 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 142,000 liters (37,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 64,000 liters (17,000 gal) 2 0

6 Slag Conveyor Drag chain 12 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 12 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 12 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 201,000 liters (53,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 64,000 liters (17,000 gal) 2 0

12 Grey Water Pumps Centrifugal 230 lpm @ 430 m H2O

(60 gpm @ 1,420 ft H2O) 2 2

13 Grey Water Recycle Heat 

Exchanger Shell and tube 52,200 kg/hr (30,000 lb/hr) 2 0

14 Slag Storage Bin Vertical, field erected 890 tonne (980 tons) 2 0

15 Unloading Equipment Telescoping chute 100 tonne/hr (110 tph) 1 0

Case B4B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 230 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 79 MVA, 3-ph, 60 Hz 2 0
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159

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 51 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 8 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B4B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.3.11 Case B4B - Cost Estimating Results

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-71 shows a 

detailed breakdown of the capital costs; Exhibit 3-72 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-73 shows the initial and annual O&M costs; and Exhibit 3-74 shows the COE 

breakdown. 

The estimated TPC of the E-GasTM gasifier with CO2 capture is $3,540/kW. Process 

contingency represents 4.1 percent of the TPC, and project contingency represents 13.9 percent. 

The COE, including CO2 T&S costs of $9.8/MWh, is $151.8/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

160

Exhibit 3-71 Case B4B total plant cost details

Case: B4B – E-GasTM IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,536 $0 $2,186 $0 $6,722 $672 $0 $1,479 $8,873 $17

1.2 Coal Stackout & Reclaim $5,862 $0 $1,402 $0 $7,263 $726 $0 $1,598 $9,587 $19

1.3 Coal Conveyors & Yd Crush $5,450 $0 $1,387 $0 $6,836 $684 $0 $1,504 $9,024 $18

1.4 Other Coal Handling $1,426 $0 $321 $0 $1,747 $175 $0 $384 $2,306 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $3,029 $7,916 $0 $10,945 $1,095 $0 $2,408 $14,447 $28

Subtotal $17,273 $3,029 $13,211 $0 $33,513 $3,351 $0 $7,373 $44,238 $86

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,937 $465 $300 $0 $2,702 $270 $0 $594 $3,566 $7

2.3 Slurry Prep & Feed $26,425 $0 $11,591 $0 $38,015 $3,802 $0 $8,363 $50,180 $98

2.4 Misc. Coal Prep & Feed $1,065 $778 $2,292 $0 $4,135 $414 $0 $910 $5,459 $11

2.9 Coal & Sorbent Feed Foundation $0 $3,907 $3,352 $0 $7,259 $726 $0 $1,597 $9,582 $19

Subtotal $29,427 $5,150 $17,535 $0 $52,112 $5,211 $0 $11,465 $68,788 $134

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,381 $5,834 $3,059 $0 $12,274 $1,227 $0 $2,700 $16,202 $32

3.2 Water Makeup & Pretreating $868 $90 $477 $0 $1,434 $143 $0 $473 $2,051 $4

3.3 Other Feedwater Subsystems $1,901 $628 $561 $0 $3,090 $309 $0 $680 $4,079 $8

3.4 Service Water Systems $507 $1,012 $3,488 $0 $5,007 $501 $0 $1,652 $7,160 $14

3.5 Other Boiler Plant Systems $2,735 $1,022 $2,515 $0 $6,272 $627 $0 $1,380 $8,279 $16

3.6 FO Supply Sys & Nat Gas $17,726 $693 $642 $0 $19,061 $1,906 $0 $4,193 $25,160 $49

3.7 Waste Treatment Equipment $1,174 $0 $727 $0 $1,901 $190 $0 $627 $2,719 $5

3.8 Misc. Power Plant Equipment $1,294 $173 $672 $0 $2,140 $214 $0 $706 $3,060 $6

Subtotal $29,586 $9,452 $12,142 $0 $51,179 $5,118 $0 $12,413 $68,710 $134

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $137,262 $0 $76,506 $0 $213,769 $21,377 $29,564 $40,623 $305,333 $594

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $222,841 $0 w/equip. $0 $222,841 $22,284 $0 $24,513 $269,638 $525

4.4 LT Heat Recovery & FG Saturation $28,817 $0 $10,949 $0 $39,766 $3,977 $0 $8,749 $52,492 $102

4.5 Misc. Gasification Equipment w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.6 Flare Stack System $0 $1,981 $801 $0 $2,782 $278 $0 $612 $3,672 $7

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $9,765 $5,824 $0 $15,589 $1,559 $0 $4,287 $21,434 $42

Subtotal $388,921 $11,746 $94,080 $0 $494,747 $49,475 $29,564 $78,784 $652,569 $1,271

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $162,818 $0 w/equip. $0 $162,818 $16,282 $32,564 $42,333 $253,996 $495

5A.2 Elemental Sulfur Plant $12,406 $2,418 $15,897 $0 $30,721 $3,072 $0 $6,759 $40,552 $79

5A.3 Mercury Removal $1,867 $0 $1,411 $0 $3,278 $328 $164 $754 $4,524 $9

5A.4 Shift Reactors $8,605 $0 $3,440 $0 $12,044 $1,204 $0 $2,650 $15,898 $31

5A.5 Particulate Removal w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

161

Case: B4B – E-GasTM IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.6 Blowback Gas Systems $657 $369 $206 $0 $1,232 $123 $0 $271 $1,626 $3

5A.7 Fuel Gas Piping $0 $926 $606 $0 $1,532 $153 $0 $337 $2,022 $4

5A.9 HGCU Foundations $0 $838 $565 $0 $1,403 $140 $0 $463 $2,007 $4

Subtotal $186,353 $4,551 $22,125 $0 $213,029 $21,303 $32,727 $53,566 $320,626 $624

5B CO2 Compression

5B.2 CO2 Compression & Drying $40,408 $6,061 $17,509 $0 $63,978 $6,398 $0 $14,075 $84,451 $164

Subtotal $40,408 $6,061 $17,509 $0 $63,978 $6,398 $0 $14,075 $84,451 $164

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $306

6.9 Combustion Turbine Foundations $0 $923 $1,068 $0 $1,992 $199 $0 $657 $2,848 $6

Subtotal $111,210 $923 $8,950 $0 $121,083 $12,108 $11,909 $14,948 $160,049 $312

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,570 $0 $5,725 $0 $35,295 $3,530 $0 $3,882 $42,707 $83

7.3 Ductwork $0 $2,109 $1,479 $0 $3,588 $359 $0 $789 $4,736 $9

7.4 Stack $4,071 $0 $1,519 $0 $5,590 $559 $0 $615 $6,763 $13

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,553 $155 $0 $512 $2,221 $4

Subtotal $33,641 $2,884 $9,501 $0 $46,026 $4,603 $0 $5,799 $56,428 $110

8 Steam Turbine Generator

8.1 Steam TG & Accessories $36,358 $0 $5,336 $0 $41,695 $4,169 $0 $4,586 $50,450 $98

8.2 Turbine Plant Auxiliaries $219 $0 $500 $0 $719 $72 $0 $79 $870 $2

8.3 Condenser & Auxiliaries $3,130 $0 $1,764 $0 $4,894 $489 $0 $538 $5,922 $12

8.4 Steam Piping $15,068 $0 $6,534 $0 $21,603 $2,160 $0 $5,941 $29,703 $58

8.9 TG Foundations $0 $1,034 $1,827 $0 $2,861 $286 $0 $944 $4,091 $8

Subtotal $54,776 $1,034 $15,962 $0 $71,771 $7,177 $0 $12,089 $91,037 $177

9 Cooling Water System

9.1 Cooling Towers $4,540 $0 $1,466 $0 $6,006 $601 $0 $991 $7,597 $15

9.2 Circulating Water Pumps $2,187 $0 $164 $0 $2,351 $235 $0 $388 $2,974 $6

9.3 Circ. Water System Auxiliaries $190 $0 $27 $0 $217 $22 $0 $36 $274 $1

9.4 Circ. Water Piping $0 $8,426 $2,041 $0 $10,468 $1,047 $0 $2,303 $13,817 $27

9.5 Make-up Water System $480 $0 $660 $0 $1,140 $114 $0 $251 $1,505 $3

9.6 Component Cooling Water Sys $963 $1,152 $791 $0 $2,907 $291 $0 $639 $3,837 $7

9.9 Circ. Water System Foundations $0 $2,765 $4,913 $0 $7,678 $768 $0 $2,534 $10,980 $21

Subtotal $8,360 $12,344 $10,063 $0 $30,767 $3,077 $0 $7,142 $40,985 $80

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $20,691 $0 $10,134 $0 $30,825 $3,083 $0 $3,391 $37,299 $73

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $680 $0 $734 $0 $1,414 $141 $0 $233 $1,789 $3

10.7 Ash Transport & Feed Equipment $935 $0 $218 $0 $1,154 $115 $0 $190 $1,459 $3

10.8 Misc. Ash Handling Equipment $1,408 $1,725 $512 $0 $3,644 $364 $0 $601 $4,610 $9

10.9 Ash/Spent Sorbent Foundation $0 $57 $75 $0 $132 $13 $0 $44 $189 $0

Subtotal $23,714 $1,782 $11,674 $0 $37,169 $3,717 $0 $4,459 $45,346 $88
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

162

Case: B4B – E-GasTM IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 514 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11 Accessory Electric Plant

11.1 Generator Equipment $1,124 $0 $1,095 $0 $2,219 $222 $0 $244 $2,685 $5

11.2 Station Service Equipment $5,488 $0 $505 $0 $5,993 $599 $0 $659 $7,252 $14

11.3 Switchgear & Motor Control $10,130 $0 $1,883 $0 $12,013 $1,201 $0 $1,982 $15,196 $30

11.4 Conduit & Cable Tray $0 $5,147 $15,866 $0 $21,013 $2,101 $0 $5,779 $28,893 $56

11.5 Wire & Cable $0 $9,924 $6,038 $0 $15,961 $1,596 $0 $4,389 $21,947 $43

11.6 Protective Equipment $0 $799 $2,967 $0 $3,766 $377 $0 $621 $4,764 $9

11.7 Standby Equipment $269 $0 $268 $0 $536 $54 $0 $88 $678 $1

11.8 Main Power Transformers $19,358 $0 $167 $0 $19,525 $1,952 $0 $3,222 $24,699 $48

11.9 Electrical Foundations $0 $175 $477 $0 $652 $65 $0 $215 $933 $2

Subtotal $36,369 $16,045 $29,264 $0 $81,678 $8,168 $0 $17,200 $107,046 $208

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,292 $0 $880 $0 $2,173 $217 $109 $375 $2,873 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $297 $0 $194 $0 $491 $49 $25 $113 $678 $1

12.7 Computer & Accessories $6,893 $0 $225 $0 $7,119 $712 $356 $819 $9,005 $18

12.8 Instrument Wiring & Tubing $0 $2,654 $5,023 $0 $7,677 $768 $384 $2,207 $11,035 $21

12.9 Other I & C Equipment $4,608 $0 $2,283 $0 $6,891 $689 $345 $1,189 $9,113 $18

Subtotal $13,090 $2,654 $8,606 $0 $24,350 $2,435 $1,217 $4,702 $32,705 $64

13 Improvements to Site

13.1 Site Preparation $0 $121 $2,743 $0 $2,864 $286 $0 $945 $4,095 $8

13.2 Site Improvements $0 $2,146 $3,033 $0 $5,179 $518 $0 $1,709 $7,406 $14

13.3 Site Facilities $3,845 $0 $4,316 $0 $8,161 $816 $0 $2,693 $11,670 $23

Subtotal $3,845 $2,266 $10,092 $0 $16,203 $1,620 $0 $5,347 $23,171 $45

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,691 $3,831 $0 $6,521 $652 $0 $1,076 $8,250 $16

14.3 Administration Building $0 $1,042 $756 $0 $1,798 $180 $0 $297 $2,274 $4

14.4 Circulation Water Pumphouse $0 $196 $104 $0 $299 $30 $0 $49 $378 $1

14.5 Water Treatment Buildings $0 $713 $696 $0 $1,409 $141 $0 $232 $1,782 $3

14.6 Machine Shop $0 $533 $365 $0 $898 $90 $0 $148 $1,136 $2

14.7 Warehouse $0 $861 $556 $0 $1,417 $142 $0 $234 $1,792 $3

14.8 Other Buildings & Structures $0 $516 $401 $0 $917 $92 $0 $202 $1,211 $2

14.9 Waste Treating Building & Str. $0 $1,153 $2,202 $0 $3,356 $336 $0 $738 $4,430 $9

Subtotal $0 $8,023 $9,089 $0 $17,112 $1,711 $0 $3,086 $21,909 $43

Total $976,972 $87,945 $289,801 $0 $1,354,718 $135,472 $75,418 $252,447 $1,818,056 $3,540
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Exhibit 3-72 Case B4B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $16,220 $32

1 Month Maintenance Materials $3,663 $7

1 Month Non-fuel Consumables $690 $1

1 Month Waste Disposal $459 $1

25% of 1 Months Fuel Cost at 100% CF $3,028 $6

2% of TPC $36,361 $71

Total $60,421 $118

Inventory Capital

60-day supply of fuel and consumables at 100% CF $25,185 $49

0.5% of TPC (spare parts) $9,090 $18

Total $34,275 $67

Other Costs

Initial Cost for Catalyst and Chemicals $17,040 $33

Land $900 $2

Other Owner's Costs $272,708 $531

Financing Costs $49,088 $96

Total Overnight Costs (TOC) $2,252,488 $4,386

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,567,836 $5,000
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Exhibit 3-73 Case B4B initial and annual operating and maintenance costs

Case: B4B – E-GasTM IGCC w/ CO2 Cost Base: Jun 2011

Plant Size (MW,net): 514 Heat Rate-net (Btu/kWh): 11,002 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 10.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 16.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,233,658 $14.084

Maintenance Labor: $18,718,137 $36.444

Administrative & Support Labor: $6,487,949 $12.632

Property Taxes and Insurance: $36,361,120 $70.795

Total: $68,800,863 $133.955

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $35,160,939 $9.76861

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 4,145 $1.67 $0 $2,026,257 $0.56295

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 24,697 $0.27 $0 $1,931,496 $0.53662

Carbon (Mercury Removal) (lb): 177,789 304 $5.50 $977,839 $488,920 $0.13583

Shift Catalyst (ft3): 6,484 4.44 $771.99 $5,005,557 $1,001,111 $0.27813

Selexol Solution (gal): 300,533 98 $36.79 $11,056,980 $1,055,946 $0.29337

Claus Catalyst (ft3): w/equip. 2.00 $203.15 $0 $118,896 $0.03303

Subtotal: $17,040,376 $6,622,626 $1.83994

Waste Disposal

Spent Mercury Catalyst (lb.): 0 304 $0.65 $0 $57,790 $0.01606

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 593 $25.11 $0 $4,348,431 $1.20811

 Subtotal: $0 $4,406,221 $1.22416

By-Products

Sulfur (tons): 0 145 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $17,040,376 $46,189,787 $12.83271

Fuel Cost

Illinois Number 6 (ton): 0 5,811 $68.54 $0 $116,290,256 $32.30842

Total: $0 $116,290,256 $32.30842

Exhibit 3-74 Case B4B COE breakdown

Component Value, $/MWh Percentage

Capital 77.6 55%

Fixed 19.1 13%

Variable 12.8 9%

Fuel 32.3 23%

Total (Excluding T&S) 141.9 N/A

CO2 T&S 9.9 7%

Total (Including T&S) 151.8 N/A
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3.4 General Electric Energy IGCC Cases

This section contains an evaluation of three GEE plant designs (radiant-only [with and without 

CO2 capture] and quench-only [with CO2 capture]). Cases B5A and B5B are based on the GEE 

gasifier in the “radiant-only” configuration and Case B5B-Q is based on the GEE gasifier in the 

“quench-only” configuration. GEE offers three design configurations (50):

• Quench: In this configuration, the hot syngas exiting the gasifier passes through a pool of 

water to quench the temperature to 289°C (550°F) before entering the syngas scrubber. It 

is the simplest and lowest capital cost design, but also the least efficient. 

• Radiant: In this configuration, the hot syngas exiting the gasifier passes through a radiant 

syngas cooler where it is cooled from about 1,316°C (2,400°F) to 677°C (1,250°F), and 

then passes through a water quench where the syngas is further cooled to about 232°C 

(450°F) prior to entering the syngas scrubber. Relative to the quench configuration, the 

radiant design offers increased output, higher efficiency, improved reliability/availability, 

and results in the lowest COE. This configuration was chosen by GEE and Bechtel for 

the design of their reference plant.

• Radiant-Convective: In this configuration, the hot syngas exiting the gasifier passes 

through a radiant syngas cooler where it is cooled from about 1,316°C (2,400°F) to 

760°C (1,400°F), then passes over a pool of water where particulate is removed but the 

syngas is not quenched, then through a convective syngas cooler where the syngas is 

further cooled to about 371°C (700°F) prior to entering additional heat exchangers or the 

scrubber. This configuration has the highest overall efficiency, but at the expense of 

highest capital cost and the lowest availability. This is the configuration used at Tampa 

Electric’s Polk Power Station.

Note that the radiant configuration includes a water quench and, based on functionality, would be 

more appropriately named radiant-quench. The term radiant is used to distinguish it from the 

radiant-convective configuration. Since radiant is the terminology used by GEE, it will be used 

throughout this report.

The balance of this section is organized in an analogous manner to Sections 3.2 and 3.3:

• Gasifier Background

• Process System Description for Case B5A

• Key Assumptions for Cases B5A, B5B, and B5B-Q

• Sparing Philosophy for Cases B5A, B5B, and B5B-Q

• Performance Results for Case B5A

• Equipment List for Case B5A

• Cost Estimates for Case B5A

• Process and System Description, Performance Results, Equipment List, and Cost 

Estimate for Cases B5B and B5B-Q

3.4.1 Gasifier Background

As mentioned in Sections 3.2.1 and 3.3.1, the “Coal Gasification Guidebook: Status, 

Application, and Technologies” report published by the EPRI provides a detailed history of the 

development of several types of gasifier technology, including the GEE gasifier, as well as 

gasifier capacity, distinguishing characteristics, and important coal characteristics. (46)
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The largest GEE gasifier is the unit at Tampa Electric, which consists of the radiant-convective 

configuration. The daily coal-handling capacity of this unit is 2,268 tonnes (2,500 tons) of 

bituminous coal. The dry gas production rate is 0.19 million Nm3

/hr (6.7 million scfh) with an 

energy content of about 1,897 million kJ/hr (HHV) (1,800 million Btu/hr). This size matches the 

F-Class CTs that are used at Tampa.

The GEE gasifier operates at the highest pressure of the three gasifiers in this report, 5.6 MPa 

(815 psia) compared to 4.2 MPa (615 psia) for E-GasTM and Shell.

The relatively high H2/CO ratio and CO2 content of GEE gasification fuel gas helps achieve low 

NOx and CO emissions in even the higher-temperature advanced CTs. (46)

In contrast to the Shell and E-GasTM gasification technologies, the GEE gasifier has a relatively 

low refractory life and a high oxygen requirement. These characteristics are more prevalent in 

the single-stage quench design, with a lower efficiency. However, the quench design has a 

significantly lower capital cost for syngas cooling. (46)

Coals with low concentrations of ash and soluble salts are preferred for use with the GEE 

gasifiers, as high levels of ash increase the oxygen requirement and soluble salts may build-up in 

concentration with high levels of process condensate recycle is used. (46)

The slurry feeding also favors the use of high-rank coals, such as bituminous coal, since their 

low inherent moisture content increases the moisture-free solids content of the slurry and thereby 

reduces oxygen requirements. (46) 

3.4.2 Process Description

In this section the overall GEE gasification process is described. The system description follows 

the BFD in Exhibit 3-75 and stream numbers reference the same exhibit. The tables in 

Exhibit 3-76 provide stream compositions, temperature, pressure, enthalpy, and flow rates for the 

numbered streams in the BFD.

3.4.2.1 Coal Grinding and Slurry Preparation

Coal receiving and handling is common to all cases and was covered in Section 3.1.1. The 

receiving and handling subsystem ends at the coal silo. Coal is then fed onto a conveyor by 

vibratory feeders located below each silo. The conveyor feeds the coal to an inclined conveyor 

that delivers the coal to the rod mill feed hopper. The feed hopper provides a surge capacity of 

about two hours and contains two hopper outlets. Each hopper outlet discharges onto a weigh 

feeder, which in turn feeds a rod mill. Each rod mill is sized to process 55 percent of the coal 

feed requirements of the gasifier. The rod mill grinds the coal and wets it with treated slurry 

water transferred from the slurry water tank by the slurry water pumps. The coal slurry is 

discharged through a trommel screen into the rod mill discharge tank, and then the slurry is 

pumped to the slurry storage tanks. The dry solids concentration of the final slurry is 63 percent. 

The Polk Power Station operates at a slurry concentration of 62-68 percent using bituminous 

coal, and ConocoPhillips presented a paper showing the slurry concentration of Illinois No. 6 

coal as 63 percent. (49) 

The coal grinding system is equipped with a dust suppression system consisting of water sprays 

aided by a wetting agent. The degree of dust suppression required depends on local 

environmental regulations. All of the tanks are equipped with vertical agitators to keep the coal 

slurry solids suspended.
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The equipment in the coal grinding and slurry preparation system is fabricated of materials 

appropriate for the abrasive environment present in the system. The tanks and agitators are 

rubber lined. The pumps are either rubber-lined or hardened metal to minimize erosion. Piping 

is fabricated of high-density polyethylene (HDPE).

3.4.2.2 Gasification

This plant utilizes two gasification trains to process a total of 5,083 tonnes/day (5,603 tpd) of 

Illinois No. 6 coal. Each of the 2 x 50 percent gasifiers operates at maximum capacity. The 

largest operating GEE gasifier is the 2,268 tonne/day (2,500 tpd) unit at Polk Power Station. 

However, that unit operates at about 2.8 MPa (400 psia). The gasifier in this report, which 

operates at 5.6 MPa (815 psia), will be able to process more coal and maintain the same gas 

residence time.

The slurry feed pump takes suction from the slurry run tank, and the discharge is sent to the feed 

injector of the GEE gasifier (stream 6). Oxygen from the ASU is vented during preparation for 

startup and is sent to the feed injector during normal operation. The air separation plant supplies 

4,171 tonnes/day (4,597 tpd) of 95 mol% oxygen to the gasifiers (stream 5) and the Claus plant 

(stream 3). Carbon conversion in the gasifier is assumed to be 98 percent, including a fines 

recycle stream.

The gasifier vessel is a refractory-lined, HP combustion chamber. The coal slurry feedstock and 

oxygen are fed through a fuel injector at the top of the gasifier vessel. The coal slurry and the 

oxygen react in the gasifier at 5.6 MPa (815 psia) and 1,316°C (2,400°F) to produce syngas.

The syngas consists primarily of hydrogen and carbon monoxide, with lesser amounts of water 

vapor and carbon dioxide, and small amounts of hydrogen sulfide, COS, methane, argon, and 

nitrogen. The heat in the gasifier liquefies coal ash. Hot syngas and molten solids from the 

reactor flow downward into a radiant heat exchanger where the syngas is cooled.

3.4.2.3 Raw Gas Cooling/Particulate Removal

Syngas is cooled from 1,316°C (2,400°F) to 677°C (1,250°F) in the radiant SGC (stream 9), and 

the molten slag solidifies in the process. The solids collect in the water sump at the bottom of 

the gasifier and are removed periodically using a lock hopper system (stream 8). The waste heat 

from this cooling is used to generate HP steam. BFW in the tubes is saturated, and then steam 

and water are separated in a steam drum. Approximately 412,096 kg/hr (908,500 lb/hr) of 

saturated steam at 13.8 MPa (2,000 psia) is produced. This steam then forms part of the general 

heat recovery system that provides steam to the steam turbine.

The syngas exiting the radiant cooler is directed downwards by a dip tube into a water sump. 

Most of the entrained solids are separated from the syngas at the bottom of the dip tube as the 

syngas goes upwards through the water. The syngas exits the quench chamber saturated at a 

temperature of 232°C (450°F).

The slag handling system removes solids from the gasification process equipment. These solids 

consist of a small amount of unconverted carbon and essentially all of the ash contained in the 

feed coal. These solids are in the form of glass, which fully encapsulates any metals. Solids 

collected in the water sump below the radiant SGC are removed by gravity and forced circulation 

of water from the lock hopper circulating pump. The fine solids not removed from the bottom of 

the quench water sump remain entrained in the water circulating through the quench chamber. In 
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order to limit the amount of solids recycled to the quench chamber, a continuous blowdown 

stream is removed from the bottom of the syngas quench. The blowdown is sent to the vacuum 

flash drum in the black water flash section. The circulating quench water is pumped by 

circulating pumps to the quench gasifier.

3.4.2.4 Syngas Scrubber/Sour Water Stripper

Syngas exiting the water quench passes to a syngas scrubber where a water wash is used to 

remove remaining chlorides, NH3, SO2, and PM. The syngas exits the scrubber still saturated at 

206°C (403°F) before it is preheated to 223°C (433°F) (stream 10) prior to entering the COS 

hydrolysis reactor.

The sour water stripper removes NH3, SO2, and other impurities from the scrubber and other 

waste streams. The stripper consists of a sour drum that accumulates sour water from the gas 

scrubber and condensate from SGCs. Sour water from the drum flows to the sour stripper, which 

consists of a packed column with a steam-heated reboiler. Sour gas is stripped from the liquid 

and sent to the SRU. Remaining water is sent to wastewater treatment.
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Exhibit 3-75 Case B5A block flow diagram, GEE IGCC without CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

QUENCH

AND

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

COS

HYDROLYSIS

ELEVATED

PRESSURE

ASU

GEE GASIFIER

SECTION

(RADIANT

COOLER)

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

SELEXOL

UNIT

CLAUS

PLANT

SYNGAS

H/P 

REHEAT

HRSG

2X STATE-OF-THEART F-CLASS

GAS TURBINES

1

AIR TO ASU

2 3

VENT

GAS

5

6 8

GASIFIER

OXIDANT

AS-RECEIVED

COAL

SLAG

9

10

11 12 13

14

15

17

18

19

4

20

21

TURBINE COOLING AIR

22

WATER RECYCLE TO

PROCESS DEMAND

AMBIENT AIR

FLUE GAS

STACK GAS

SYNGAS

EXPANDER

NOTE: WATER FROM TAIL

GAS COOLER MODELED, 

BUT NOT SHOWN

HYDROGENATION

REACTOR AND GAS

COOLER

16

TAIL GAS RECYCLE TO

SELEXOL

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, BUT

NOT SHOWN

CLEAN GAS

NITROGEN DILUENT

AIR

SULFUR

PRODUCT

SYNGAS

CLAUS PLANT

OXIDANT

23

CLAUS PLANT

OXIDANT

STEAM

TURBINE

24 Note: Block Flow Diagram is not 

intended to represent a complete 

material balance. Only major process 

streams and equipment are shown.

SLURRY

MIXER

7

SLURRY

WATER
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Exhibit 3-76 Case B5A stream table, GEE IGCC without capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0234 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0068 0.0099 0.0097 0.0000

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0012 0.0009 0.0009 0.0013 0.0013 0.0000

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3579 0.2825 0.2825 0.4151 0.3977 0.0002

CO2 0.0003 0.0081 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1366 0.1078 0.1079 0.1586 0.1811 0.6124

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3416 0.2696 0.2696 0.3961 0.3812 0.0000

H2O 0.0099 0.2084 0.0000 0.0003 0.0000 0.0000 0.9994 0.0000 0.1358 0.3181 0.3180 0.0012 0.0012 0.0128

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0002 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0059 0.0085 0.0086 0.1817

N2 0.7732 0.5614 0.0178 0.9919 0.0178 0.0000 0.0000 0.0000 0.0080 0.0063 0.0063 0.0092 0.0191 0.1905

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0006 0.0000 0.0021 0.0020 0.0020 0.0000 0.0000 0.0000

O2 0.2074 0.1987 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0023

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 21,872 1,065 102 19,382 5,298 0 4,829 0 22,212 28,142 28,142 19,153 19,992 951

V-L Flowrate (kg/hr) 631,159 28,895 3,290 543,851 170,484 0 87,000 0 446,029 552,590 552,590 390,592 422,589 36,883

Solids Flowrate (kg/hr) 0 0 0 0 0 211,781 0 23,236 0 0 0 0 0 0

Temperature (°C) 15 20 32 93 32 15 146 1,316 677 223 223 35 35 45

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.48 5.41 5.24 5.21 5.17

Steam Table Enthalpy (kJ/kg) A 30.23 36.81 26.67 92.52 26.67 --- 558.58 --- 1,427.78 1,067.54 1,067.44 40.35 36.92 -1.24

AspenPlus Enthalpy (kJ/kg)B -97.58 -2,311.18 4.13 63.39 4.13 -2,116.95 -15,404.71 -727.24 -5,219.35 -7,386.27 -7,386.27 -5,336.38 -5,478.96 -6,427.70

Density (kg/m3) 1.2 1.6 11.0 24.4 11.0 --- 866.9 --- 13.9 26.7 26.3 41.9 43.4 95.0

V-L Molecular Weight 28.857 27.130 32.181 28.060 32.181 --- 18.015 --- 20.081 19.636 19.636 20.393 21.138 38.795

V-L Flowrate (lbmole/hr) 48,220 2,348 225 42,729 11,679 0 10,647 0 48,969 62,042 62,042 42,225 44,075 2,096

V-L Flowrate (lb/hr) 1,391,468 63,703 7,253 1,198,986 375,853 0 191,802 0 983,326 1,218,253 1,218,253 861,109 931,649 81,312

Solids Flowrate (lb/hr) 0 0 0 0 0 466,898 0 51,227 0 0 0 0 0 0

Temperature (°F) 59 68 90 199 90 59 295 2,400 1,250 433 433 95 94 112

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 795.0 785.0 760.0 755.0 750.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.8 11.5 39.8 11.5 --- 240.1 --- 613.8 459.0 458.9 17.3 15.9 -0.5

AspenPlus Enthalpy (Btu/lb)B -42.0 -993.6 1.8 27.3 1.8 -910.1 -6,622.8 -312.7 -2,243.9 -3,175.5 -3,175.5 -2,294.2 -2,355.5 -2,763.4

Density (lb/ft3) 0.076 0.098 0.687 1.521 0.687 --- 54.120 --- 0.870 1.665 1.643 2.617 2.712 5.932

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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Exhibit 3-76 Case B5A stream table, GEE IGCC without capture (continued)

15 16 17 18 19 20 21 22 23 24

V-L Mole Fraction

Ar 0.0000 0.0040 0.0100 0.0100 0.0100 0.0092 0.0092 0.0089 0.0089 0.0000

CH4 0.0000 0.0000 0.0013 0.0013 0.0013 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0000 0.0021 0.4089 0.4089 0.4089 0.0000 0.0000 0.0000 0.0000 0.0000

CO2 0.0000 0.6947 0.1562 0.1562 0.1562 0.0003 0.0003 0.0807 0.0807 0.0000

COS 0.0000 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0415 0.3920 0.3920 0.3920 0.0000 0.0000 0.0000 0.0000 0.0000

H2O 0.0000 0.0018 0.0006 0.0006 0.0006 0.0099 0.0099 0.0638 0.0638 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0000 0.0111 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

N2 0.0000 0.2448 0.0309 0.0309 0.0309 0.7732 0.7732 0.7427 0.7427 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.2074 0.1039 0.1039 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 0 839 19,445 19,445 19,445 110,253 4,410 136,883 136,883 35,596

V-L Flowrate (kg/hr) 0 31,996 397,044 397,044 397,044 3,181,557 127,262 3,995,191 3,995,191 641,268

Solids Flowrate (kg/hr) 5,307 0 0 0 0 0 0 0 0 0

Temperature (°C) 174 38 45 241 196 15 432 589 132 561

Pressure (MPa, abs) 0.41 5.51 5.17 5.14 3.17 0.10 1.62 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A --- -5.04 54.55 365.19 296.11 30.23 463.79 741.45 235.13 3,502.79

AspenPlus Enthalpy (kJ/kg)B 138.98 -7,219.57 -5,220.07 -4,909.43 -4,978.51 -97.58 335.98 -999.91 -1,506.23 -12,467.52

Density (kg/m3) 5,288.2 97.7 40.0 24.1 16.4 1.2 7.9 0.4 0.9 35.1

V-L Molecular Weight --- 38.145 20.419 20.419 20.419 28.857 28.857 29.187 29.187 18.015

V-L Flowrate (lbmole/hr) 0 1,849 42,869 42,869 42,869 243,066 9,723 301,776 301,776 78,475

V-L Flowrate (lb/hr) 0 70,540 875,333 875,333 875,333 7,014,133 280,565 8,807,888 8,807,888 1,413,754

Solids Flowrate (lb/hr) 11,699 0 0 0 0 0 0 0 0 0

Temperature (°F) 345 100 112 465 386 59 810 1,093 270 1,043

Pressure (psia) 59.3 799.5 750.0 745.0 460.0 14.7 234.9 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A --- -2.2 23.5 157.0 127.3 13.0 199.4 318.8 101.1 1,505.9

AspenPlus Enthalpy (Btu/lb)B 59.8 -3,103.9 -2,244.2 -2,110.7 -2,140.4 -42.0 144.4 -429.9 -647.6 -5,360.1

Density (lb/ft3) 330.129 6.098 2.499 1.508 1.026 0.076 0.495 0.027 0.057 2.191

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
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3.4.2.5 COS Hydrolysis, Mercury Removal and Acid Gas Removal

Syngas exiting the scrubber (stream 10) passes through a COS hydrolysis reactor where about 

99.5 percent of the COS is converted to CO2 and H2S (Section 3.1.5). The gas exiting the COS 

reactor (stream 11) passes through a series of heat exchangers and knockout (KO) drums to 

lower the syngas temperature to 35°C (95°F) and to separate entrained water. The cooled syngas 

(stream 12) then passes through dual carbon beds to remove approximately 97 percent of the Hg 

(Section 3.1.4).

Cool, particulate-free syngas (stream 13) enters the Selexol absorber unit at approximately 

5.2 MPa (755 psia) and 34°C (94°F). In this absorber, H2S is preferentially removed from the 

fuel gas stream along with smaller amounts of CO2, COS, and other gases, such as hydrogen. 

The rich solution leaving the bottom of the absorber is heated against the lean solvent returning 

from the regenerator before entering the H2S concentrator. A portion of the non-sulfur bearing 

absorbed gases is driven from the solvent in the H2S concentrator using N2 from the ASU as the 

stripping medium. The temperature of the H2S concentrator overhead stream is reduced prior to 

entering the reabsorber where a second stage of H2S absorption occurs. The rich solvent from 

the reabsorber is combined with the rich solvent from the absorber and sent to the stripper where 

it is regenerated through the indirect application of thermal energy via condensation of LP steam 

in a reboiler. The stripper acid gas stream (stream 14), consisting of 18 percent H2S and 

61 percent CO2 (with the balance mostly N2), is then sent to the Claus unit.

3.4.2.6 Claus Unit

Acid gas from the first-stage stripper of the Selexol unit is routed to the Claus plant. The Claus 

plant partially oxidizes the H2S in the acid gas to elemental sulfur. About 5,307 kg/hr (11,699 

lb/hr) of elemental sulfur (stream 15) are recovered from the fuel gas stream. This value 

represents an overall sulfur recovery efficiency of 99.6 percent.

Acid gas from the Selexol unit is preheated to 232°C (450°F). A portion of the acid gas along 

with all of the sour gas from the stripper and oxygen from the ASU are fed to the Claus furnace. 

In the furnace, H2S is catalytically oxidized to SO2 at a furnace temperature greater than 1,343°C 

(2,450°F), which must be maintained in order to thermally decompose all of the NH3 present in 

the sour gas stream.

Following the thermal stage and condensation of sulfur, two reheater and two sulfur converters 

are used to obtain a per-pass H2S conversion of approximately 99.9 percent. The Claus Plant tail 

gas is hydrogenated and recycled back to the Selexol process (stream 16). In the furnace waste 

heat boiler, 12,432 kg/hr (27,408 lb/hr) of 4.2 MPa (605 psia) steam are generated. This steam is 

used to satisfy all Claus process preheating and reheating requirements as well as to produce 

some steam for the medium-pressure steam header. The sulfur condensers produce 0.34 MPa 

(50 psig) of steam for the LP steam header and 2.9 MPa (415 psig) for IP steam.

3.4.2.7 Power Block

Clean syngas exiting the Selexol absorber is re-heated (stream 18) using HP BFW and then 

expanded to 3.2 MPa (460 psia) using an expansion turbine (stream 19). The syngas stream is 

diluted with nitrogen from the ASU (stream 4) and enters the state-of-the-art 2008 F-class CT 

burner. The CT compressor provides combustion air to the burner and also 17 percent of the air 

requirements in the ASU (stream 21). The exhaust gas exits the CT at 589°C (1,093°F) (stream 

22) and enters the HRSG where additional heat is recovered until the flue gas exits the HRSG at 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

173

132°C (270°F) (stream 23) and is discharged through the plant stack. The steam raised in the 

HRSG is used to power an advanced, commercially available steam turbine using a 12.4 

MPa/562°C/562°C (1,800 psig/1,043°F/1,043°F) steam cycle 132°C (270°F) (stream 23) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced, 

commercially available steam turbine using a 12.4 MPa/562°C/562°C (1,800 

psig/1,043°F/1,043°F) steam cycle.

3.4.2.8 Air Separation Unit

The elevated pressure ASU was described in Section 3.1.2. In Case B5A the ASU is designed to 

produce a nominal output of 4,171 tonnes/day (4,597 tpd) of 95 mol% O2 for use in the gasifier 

(stream 5) and Claus plant (stream 3). The plant is designed with two production trains. The air 

compressor is powered by an electric motor. Approximately 13,051 tonnes/day (14,387 tpd) of 

nitrogen is also recovered, compressed, and used for dilution in the CT combustor (stream 4). 

About 4 percent of the CT air is used to supply approximately 17 percent of the ASU air 

requirements (stream 21) in the non-capture case.

3.4.2.9 Balance of Plant

Balance of plant items were covered in Sections 3.1.9, 3.1.10, and 3.1.12.

3.4.3 Key System Assumptions

System assumptions for cases B5A, B5B, and B5B-Q, GEE IGCC with and without CO2 capture, 

are presented in Exhibit 3-77.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

174

Exhibit 3-77 GEE IGCC plant study configuration matrix

Case B5A B5B B5B-Q

Gasifier Pressure, MPa 

(psia) 5.6 (815) 5.6 (815) 5.6 (815)

O2:Coal Ratio, kg O2/kg dry 

coal 0.91 0.91 0.91

Carbon Conversion, % 98 98 98

Syngas HHV at Gasifier 

Outlet, kJ/Nm3 (Btu/scf) 8,663 (233) 8,644 (232) 8,655 (232)

Steam Cycle, MPa/°C/°C 

(psig/°F/°F)

12.4/562/562 

(1,800/1,043/1,043)

12.4/534/534 

(1,800/994/994)

12.4/534/534 

(1,800/994/994)

Condenser Pressure, mm 

Hg 

(in Hg)

51 (2.0) 51 (2.0) 51 (2.0)

Combustion Turbine

2x State-of-the-Art 2008 

F-Class 

(232 MW output each)

2x State-of-the-Art 2008 

F-Class 

(232 MW output each)

2x State-of-the-Art 2008 

F-Class 

(232 MW output each)

Gasifier Technology GEE Radiant GEE Radiant GEE Quench

Oxidant 95 vol% Oxygen 95 vol% Oxygen 95 vol% Oxygen

Coal Illinois No. 6 Illinois No. 6 Illinois No. 6

Coal Slurry Solids Content, 

% 63 63 63

COS Hydrolysis Yes Occurs in SGS Occurs in SGS

Sour Gas Shift No Yes Yes

H2S Separation Selexol Selexol 1st Stage Selexol 1st Stage

Sulfur Removal, % 99.7 99.9 99.8

Sulfur Recovery

Claus Plant with Tail Gas 

Recycle to Selexol/ 

Elemental Sulfur

Claus Plant with Tail Gas 

Recycle to Selexol/ 

Elemental Sulfur

Claus Plant with Tail Gas 

Recycle to Selexol/ 

Elemental Sulfur

Particulate Control Water Quench, Scrubber, 

and AGR Absorber

Water Quench, Scrubber, 

and AGR Absorber

Water Quench, Scrubber, 

and AGR Absorber

Mercury Control Carbon Bed Carbon Bed Carbon Bed

NOx Control

Multi Nozzle Quiet 

Combustor (MNQC) 

(LNB) and N2 Dilution

MNQC (LNB) and N2

Dilution

MNQC (LNB) and N2

Dilution

CO2 Separation N/A Selexol 2nd Stage Selexol 2nd Stage

Overall Carbon Capture N/A 90.0% 90.0%

CO2 Sequestration N/A Off-site Saline Formation Off-site Saline Formation
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

175

3.4.3.1 Balance of Plant – Cases B5A, B5B, and B5B-Q

The balance of plant assumptions are common to all cases and are presented in Exhibit 3-11.

3.4.4 Sparing Philosophy

The sparing philosophy for cases B5A, B5B, and B5B-Q is provided below. Dual trains are used 

to accommodate the size of commercial CTs. There is no redundancy other than normal sparing 

of rotating equipment. The plant design consists of the following major subsystems:

• Two ASUs (2 x 50%)

• Two trains of slurry preparation and slurry pumps (2 x 50%)

• Two trains of gasification, including gasifier, SGC, quench and scrubber (2 x 50%)

• Two trains of syngas clean-up process (2 x 50%)

• Two trains of Selexol AGR, single-stage in Case B5A and two-stage in Case B5B, 

(2 x 50%) and one Claus-based SRU (1 x 100%)

• Two CO2 compression systems (2 x 50%) in cases B5B and B5B-Q

• Two CT/HRSG tandems (2 x 50%)

• One steam turbine (1 x 100%)

3.4.5 Case B5A - Performance Results

The plant produces a net output of 622 MWe at a net plant efficiency of 39.0 percent (HHV 

basis). GEE has reported a net plant efficiency of 38.5 percent for their reference plant, and they 

also presented a range of efficiencies of 38.5-40 percent depending on fuel type. (16), (51) 

Typically the higher efficiencies result from fuel blends that include petroleum coke.

Overall performance for the plant is summarized in Exhibit 3-78; Exhibit 3-79 provides a 

detailed breakdown of the auxiliary power requirements. The ASU accounts for approximately 

78 percent of the auxiliary load between the main air compressor, nitrogen compressor, oxygen 

compressor, and ASU auxiliaries. The cooling water system, including the CWPs and the 

cooling tower fan, accounts for approximately 5 percent of the auxiliary load, and the BFW 

pumps account for an additional 3 percent. All other individual auxiliary loads are less than 3 

percent of the total.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

176

Exhibit 3-78 Case B5A plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 8

Steam Turbine Power, MWe 276

Total Gross Power, MWe 748

Air Separation Unit Main Air Compressor, kWe 53,820

Oxygen Compressor, kWe 10,260

Nitrogen Compressors, kWe 33,350

CO2 Compression, kWe 0

Acid Gas Removal, kWe 2,590

Balance of Plant, kWe 25,840

Total Auxiliaries, MWe 126

Net Power, MWe 622

HHV Net Plant Efficiency (%) 39.0%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 9,240 (8,758)

HHV Cold Gas Efficiency, % 79.6%

HHV Combustion Turbine Efficiency, % 37.5%

LHV Net Plant Efficiency (%) 40.4%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 8,912 (8,447)

LHV Cold Gas Efficiency, % 76.2%

LHV Combustion Turbine Efficiency, % 40.6%

Steam Turbine Cycle Efficiency, % 43.3%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,323 (7,889)

Condenser Duty, GJ/hr (MMBtu/hr) 1,536 (1,456)

As-Received Coal Feed, kg/hr (lb/hr) 211,781 (466,898)

HHV Thermal Input, kWt 1,596,309

LHV Thermal Input, kWt 1,539,660

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.029 (7.6)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.023 (6.1)

O2:Coal 0.761
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

177

Exhibit 3-79 Case B5A plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 8

Steam Turbine Power, MWe 276

Total Gross Power, MWe 748

Auxiliary Load Summary

Coal Handling, kWe 460

Coal Milling, kWe 2,180

Sour Water Recycle Slurry Pump, kWe 180

Slag Handling, kWe 1,120

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 53,820

Oxygen Compressor, kWe 10,260

Nitrogen Compressors, kWe 33,350

Feedwater Pumps, kWe 3,980

Quench Water Pump, kWe 520

Syngas Recycle Compressor, kWe 0

CO2 Compression, kWe 0

Scrubber Pumps, kWe 220

Acid Gas Removal, kWe 2,590

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 4,220

Ground Water Pumps, kWe 430

Cooling Tower Fans, kWe 2,180

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 2,090

Miscellaneous Balance of PlantA,B, kWe 3,000

Transformer Losses, kWe 2,680

Total Auxiliaries, MWe 126

Net Power, MWe 622

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads

3.4.5.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case B5A is presented in Exhibit 3-80. All HCl is 

assumed to be removed and is, therefore, not reported.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

178

Exhibit 3-80 Case B5A air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.001 (0.001) 21 (24) 0.004 (0.009)

NOx 0.025 (0.059) 1,023 (1,128) 0.195 (0.430)

Particulates 0.003 (0.0071) 123 (136) 0.023 (0.052)

Hg 1.77E-7 (4.12E-7) 0.007 (0.008) 1.36E-6 (3.00E-6)

CO2 85 (197) 3,407,878 (3,756,542) 650 (1,434)

CO2C - - 782 (1,724)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the Selexol 

AGR process. The AGR process removes over 99 percent of the sulfur compounds in the fuel 

gas down to a level of less than 30 ppmv. This results in a concentration in the flue gas of less 

than 4 ppmv. The H2S-rich regeneration gas from the AGR system is fed to a Claus plant, 

producing elemental sulfur. The Claus plant tail gas is hydrogenated to convert all sulfur species 

to H2S and then recycled back to the Selexol process, thereby eliminating the need for a tail gas 

treatment unit.

NOx emissions are limited by nitrogen dilution of the syngas to 15 ppmvd (as NO2 @15 percent 

O2). Ammonia in the syngas is removed with process condensate prior to the low-temperature 

AGR process and ultimately destroyed in the Claus plant burner. This helps lower NOx levels as 

well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

CO2 emissions represent the uncontrolled discharge from the process.

The carbon balance for the plant is shown in Exhibit 3-81. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon in the air is not neglected here since 

the Aspen model accounts for air components throughout. Carbon leaves the plant as unburned 

carbon in the slag and as CO2 in the stack gas and ASU vent gas.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

179

Exhibit 3-81 Case B5A carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 134,999 (297,623) Stack Gas 132,715 (292,586)

Air (CO2) 519 (1,143) CO2 Product 0 (0)

ASU Vent 103 (227)

Slag 2,700 (5,952)

Total 135,518 (298,766) Total 135,518 (298,766)

Exhibit 3-82 shows the sulfur balances for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-82 Case B5A sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,308 (11,702) Stack Gas 2 (3)

CO2 Product 0 (0)

Elemental Sulfur (11,699)

Total 5,308 (11,702) Total 5,308 (11,702)

Exhibit 3-83 shows the overall water balance for the plant. The water balance was explained in 

cases B1A (Shell) and B4A (E-GasTM), but is also presented here for completeness

Water demand represents the total amount of water required for a particular process. Some water 

is recovered within the process, primarily as syngas condensate, and is re-used as internal 

recycle. The difference between demand and recycle is raw water withdrawal. Raw water 

withdrawal is defined as the water removed from the ground or diverted from a surface-water 

source for use in the plant. For this report, it was assumed to be provided 50 percent by a POTW 

and 50 percent from groundwater. Raw water withdrawal can be represented by the water 

metered from a raw water source and used in the plant processes for any and all purposes, such 

as cooling tower makeup, BFW makeup, quench system makeup, and slag handling makeup. 

The difference between water withdrawal and process water discharge is defined as water 

consumption and can be represented by the portion of the raw water withdrawn that is 

evaporated, transpired, incorporated into products, or otherwise not returned to the water source 

from which it was withdrawn. Water consumption represents the net impact of the plant process 

on the water source balance.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

180

Exhibit 3-83 Case B5A water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.50 (133) 0.50 (133) – – –

Slurry Water 1.45 (384) 1.45 (384) – – –

Quench/Wash 2.75 (726) 0.90 (237) 1.85 (489) – 1.85 (489)

Humidifier – – – – –

SWS Blowdown – – – 0.03 (7.54) -0.03 (-7.54)

Condenser Makeup 0.20 (54) – 0.20 (54) – 0.20 (54)

 BFW Makeup 0.20 (54) – 0.20 (54) – 0.20 (54)

 Gasifier Steam – – – – –

 Shift Steam – – – – –

 CT Steam Dilution – – – – –

Cooling Tower 16.43 

(4,341) 0.49 (129) 15.94 (4,211) 3.70 (976) 12.25 (3,235)

 BFW Blowdown – 0.20 (54) -0.20 (-54) – -0.20 (-54)

 SWS Blowdown – 0.29 (75.38) -0.29 (-

75.38) – -0.29 (-75.38)

Total 21.34 

(5,638) 3.34 (883) 18.00 (4,755) 3.72 (984) 14.27 (3,771)

3.4.5.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-84 through 

Exhibit 3-86:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-87. The power out is 

the combined CT, steam turbine, and expander power prior to generator losses. The power at the 

generator terminals (shown in Exhibit 3-78) is calculated by multiplying the power out by a 

combined generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

181

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

182

Exhibit 3-84 Case B5A coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5A

GEE GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-B5A-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

1,391,468 W

59 T

15 P

13 H

375,853 W

90 T

125 P

11 H

375,853 W

241 T

940 P

41 H

To Claus Plant

7,253 W

90 T

125 P

11 H

63,703 W

68 T

16 P

16 H

1,073,388 W

90 T

56 P

14 H

150,594 W

50 T

182 P

3 H

5

1

3

2

Slurry Mix 

Tank

Slag

466,898 W

59 T

15 P

191,802 W

295 T

840 P

240 H

51,227 W

2,400 T

815 P

1,198,986 W

389 T

384 P

88 H

658,700 W

160 T

840 P

1,390,226 W

100 T

190 P

18 H

6

Air From GT

Compressor

280,565 W

220 T

225 P

51 H

280,565 W

810 T

235 P

199 H

1,198,986 W

199 T

384 P

40 H

21

N2 Boost

Compressor 24,996 W

199 T

384 P

40 H

24,996 W

376 T

785 P

84 H

GE Energy 

Gasifier

Radiant

Syngas

Cooler

Raw Fuel Gas

Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

983,326 W

1,250 T

805 P

612 H

1,218,253 W

403 T

800 P

446 H

Syngas

Quench

1,346,408 W

450 T

805 P

536 H

8

9

363,082 W

371 T

1,200 P

329 H

370,996 W

403 T

800 P

418 H

To Fuel Gas 

Preheater

From Fuel Gas 

Preheater

To Sour 

Water Stripper

From Sour 

Water Stripper

66,538 W

293 T

115 P

236 H

7

370,996 W

150 T

1,205 P

118 H

N2 to GT 

Combustor

To HP Economizer 1

From HP 

Economizer 2

N2 to AGR

Ambient Air

To 

Superheater

From HP 

Economizer 2

Notes:

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,758 Btu/kWh

Milled Coal

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

183

Exhibit 3-85 Case B5A syngas cleanup heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5A

GEE GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-B5A-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

2 OF 3

Mercury 

Removal

Knock

Out

Drum

Sour

Drum

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Syngas

Coolers

Sour

Stripper

1,218,253 W

403 T

800 P

458 H

931,649 W

94 T

755 P

16 H

81,312 W

112 T

750 P

-1 H

875,333 W

386 T

460 P

127 H

11,699 W

79,720 W

450 T

59 P

250 H

2,855 W

235 T

65 P

405 H

15

12

16

71,391 W

120 T

57 P

32 H

861,109 W

95 T

760 P

17 H

9,181 W

118 T

57 P

44 H

70,540 W

100 T

800 P

-2 H

17

875,333 W

112 T

750 P

23 H

COS Hydrolysis 1,218,253 W

433 T

785 P

459 H

1,218,253 W

433 T

795 P

459 H

10 11

Clean 

Gas

Acid 

Gas

13

AGR- Selexol

14

Fuel Gas

Expander

19

875,333 W

465 T

745 P

157 H

18

N2 to AGR

24,996 W

90 T

785 P

9 H

Hydrogenation 

and Tail Gas 

Cooling

Tail Gas Recycle

Compressor

621,422 W

Blowdown to Waste 

Water Treatment

Raw Syngas

COS Hydrolysis

Preheater

To Superheater

From HP 

Economizer 2

From Syngas 

Scrubber Makeup Water

Reboiler

To Coal Slurry, Syngas 

Quench, and Slag Quench

Knock Out

From Gland Steam 

Condenser

To Syngas 

Cooling

115 T

7,253 W

90 T

125 P

11 H

3

7,253 W

450 T

125 P

92 H

Claus Oxygen

Preheater

To 

Deaerator

From IP 

BFW

From ASU

Fuel Gas To CT

To Syngas 

Scrubber and HP 

Economizer 1

Fuel Gas 

Preheater

From Syngas 

Scrubber and HP 

Economizer 2

To Preheater and 

LP Evaporator

From Tail Gas 

Cooler and LP 

Economizer

Notes:

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,758 Btu/kWh
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

184

Exhibit 3-86 Case B5A combined-cycle power generation heat and mass balance schematic

Source: NETL

Notes:

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5A

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5A

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B5A-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

HP

Turbine

IP

Turbine Nitrogen Diluent

Air Inlet 

Filter

Ambient Air

Steam Seal 

Regulator

Blowdown

Flash

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Fuel Gas

Generator

Generator

Condensate

Pumps

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,581,175 W

101 T

1 P

69 H

8,807,888 W

270 T

15 P

101 H

875,333 W

386 T

460 P

127 H

1,413,754 W

1,043 T

1,815 P

1,498 H

9,644 W

298 T

65 P

1,171 H

1,542,249 W

512 T

65 P

1,280 H

1,581,175 W

103 T

120 P

71 H

1,400 W

662 T

65 P

1,354 H

1,400 W

212 T

15 P

180 H

20

24

19

23

Hot Well

Condenser

Make-up

27,011 W

59 T

15 P

27 H

8,822 W

702 T

501 P

1,350 H

9,515 W

662 T

65 P

1,354 H

780 W

1,043 T

1,815 P

1,498 H

1,312 W

541 T

65 P

1,294 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas Cooler To Radiant 

Syngas Cooler

From Radiant Syngas 

Cooler

To ASU and Fuel 

Gas Preheater

Deaerator

HP Pump

IP Pump

From ASU and Fuel 

Gas Preheater

LP 

Evaporator

From Claus, Process Extraction, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown Hot Reheat

8,807,888 W

1,093 T

15 P

319 H 22

To WWT

Process Extraction

LP Pump

235 T

274 T

1,932,503 W

274 T

45 P

242 H

1,440,746 W

279 T

2,251 P

247 H

9,663 W

274 T

79 P

242 H

7,083 W

274 T

79 P

242 H 45,731 W

276 T

615 P

244 H

240,921 W

351 T

2,251 P

319 H

305 T 585 T 636 T

26,992 W

585 T

2,001 P

593 H

636 T

908,447 W

585 T

2,001 P

585 H

1,385,727 W

702 T

501 P

1,351 H

240,921 W

585 T

2,001 P

585 H

1,198,986 W

385 T

389 P

87 H

21

Air Extraction

280,565 W

810 T

235 P

199 H

387,415 W

298 T

65 P

266 H

1,581,175 W

185 T

105 P

153 H

299,058 W

298 T

65 P

1,171 H

1,000 W

1,043 T

1,815 P

1,498 H

1,000 W

212 T

15 P

180 H

42,626 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

Condensate to Tail 

Gas Cooling

To Claus

To Syngas 

Coolers

From 

Syngas 

Coolers

1,043 T

Gross Plant Power: 748 MWe

Auxiliary Load: 126 MWe

Net Plant Power: 622 MWe

Net Plant Efficiency, HHV: 39.0%

Net Plant Heat Rate: 8,758 Btu/kWh

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

185

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

186

Exhibit 3-87 Case B5A overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,747 

(5,447)

4.8 (4.6) – 5,752 

(5,451)

Air – 115.2 (109.2) – 115.2 

(109.2)

Raw Water Makeup – 67.7 (64.1) – 67.7 (64.1)

Auxiliary Power – – 453 (429) 453 (429)

TOTAL 5,747 

(5,447)

187.7 (177.9) 453 (429) 6,388 

(6,054)

Heat Out (GJ/hr)

ASU Vent – 1.1 (1.0) – 1.1 (1.0)

Slag 88.5 (83.9) 36.3 (34.4) – 124.8 

(118.3)

Stack Gas – 939 (890) – 939 (890)

Sulfur 49.2 (46.6) 0.6 (0.6) – 49.8 (47.2)

Motor Losses and Design 

Allowances

– – 53.9 (51.1) 53.9 (51.1)

Condenser – 1,536 (1,456) – 1,536 

(1,456)

Non-Condenser Cooling Tower 

Loads

– 458 (434) – 458 (434)

CO2 – – – –

Blowdown – 41.0 (38.9) – 41.0 (38.9)

CO2 Capture Losses – – – –

Ambient LossesA – 157.9 (149.6) – 157.9 

(149.6)

Power – – 2,692 

(2,552)

2,692 

(2,552)

TOTAL 137.7 

(130.5)

3,171 (3,005) 2,746 

(2,603)

6,055 

(5,739)

Unaccounted EnergyB – 333 (316) – 333 (316)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference.

3.4.6 Case B5A - Major Equipment List

Major equipment items for the GEE gasifier with no CO2 capture are shown in the following 

tables. The accounts used in the equipment list correspond to the account numbers used in the 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

187

cost estimates in Section 3.4.7. In general, the design conditions include a 10 percent 

contingency for flows and heat duties and a 21 percent contingency for heads on pumps and fans.

Case B5A – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 40 tonne (50 ton) 2 1

7 Feeder Vibratory 170 tonne/hr (190 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 170 tonne (190 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 350 tonne/hr (390 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 780 tonne (860 ton) 3 0

Case B5A – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 230 tonne/h (260 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 470 tonne (510 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with 

Agitator Field erected 287,520 liters (75,950 gal) 2 0

7 Slurry Water Pumps Centrifugal 800 lpm (210 gpm) 2 1

8 Trommel Screen Coarse 160 tonne/h (180 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 376,120 liters (99,360 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,100 lpm (800 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,128,400 liters (298,100 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,300 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,100 lpm (800 gpm) 2 2

Case B5A – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,083,000 liters (286,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,620 lpm @ 90 m H2O

(1,750 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 494,000 kg/hr (1,088,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,360 lpm @ 30 m H2O

(2,210 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

6,230 lpm @ 1,800 m H2O

(1,650 gpm @ 6,100 ft H2O)

2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

188

Equipment 

No. Description Type Design Condition Operating Qty. Spares

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal

IP water: 1,040 lpm @ 220 m 

H2O (280 gpm @ 730 ft H2O) 2 1

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 252 GJ/hr (239 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 90,400 lpm @ 20 m H2O(23,900 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

4,630 lpm @ 20 m H2O

(1,220 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

3,080 lpm @ 270 m H2O 

(810 gpm @ 880 ft H2O) 3 1

16 Filtered Water Pumps Stainless steel, single 

suction

2,090 lpm @ 50 m H2O

(550 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,002,000 liter (265,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 300 lpm (80 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B5A – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,800 tonne/day, 5.6 MPa

(3,100 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

245,000 kg/hr (541,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 336,000 kg/hr (741,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 216,000 kg/hr (476,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

215,000 kg/hr, 35°C, 5.3 MPa

(475,000 lb/hr, 95°F, 765 psia) 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

336,000 kg/hr (741,000 lb/hr) 

syngas

2 0

7 ASU Main Air 

Compressor Centrifugal, multi-stage 5,000 m3/min @ 1.3 MPa(168,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,300 tonne/day (2,500 tpd) of 

95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (41,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

10 Primary Nitrogen 

Compressor Centrifugal, multi-stage

4,000 m3/min (133,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

189

Equipment 

No. Description Type Design Condition Operating Qty. Spares

11 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

530 m3/min (19,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

12 AGR Nitrogen Boost 

Compressor

Centrifugal, singlestage

90 m3/min (3,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 5.4 MPa (790 psia)

2 0

13 Extraction Air Heat 

Exchanger

Gas-to-gas, vendor 

design

70,000 kg/hr, 432°C, 1.6 MPa

(154,000 lb/hr, 810°F, 235 psia) 2 0

Case B5A – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 215,000 kg/hr (474,000 lb/hr),

35°C (95°F), 5.2 MPa (760 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 215,000 kg/hr (474,000 lb/hr),

35°C (95°F), 5.2 MPa (760 psia) 2 0

3 Sulfur Plant Claus type 140 tonne/day (154 tpd) 1 0

4 COS Hydrolysis 

Reactor Fixed bed, catalytic 304,000 kg/hr (670,000 lb/hr),221°C (430°F), 5.4 MPa (790 psia) 2 0

5 Acid Gas Removal 

Plant Selexol 232,000 kg/hr (512,000 lb/hr),35°C (94°F), 5.2 MPa (755 psia) 2 0

6 Hydrogenation 

Reactor Fixed bed, catalytic

40,000 kg/hr (88,000 lb/hr)

232°C (450°F)

0.4 MPa (58.9 psia)

1 0

7 Tail Gas Recycle 

Compressor Centrifugal 35,000 kg/hr (78,000 lb/hr) each 1 0

Case B5A – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

218,400 kg/h (481,400 lb/h)

5.1 MPa (745 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0

Case B5A – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.4 m (27 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 352,698 kg/hr, 

12.4 MPa/561°C 

(777,565 lb/hr, 1,800 psig/1,043°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

190

Case B5A – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

291 MW

12.4 MPa/561°C/561°C 

(1,800 psig/ 1,043°F/1,043°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

320 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,690GJ/hr (1,600 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B5A – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 423,000 lpm @ 30 m(112,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,360 GJ/hr (2,240 MMBtu/hr) heat duty

1 0

Case B5A – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 244,000 liters (64,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (14 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (14 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 147,000 liters (39,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 66,000 liters (17,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (14 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (14 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (14 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 208,000 liters (55,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 50 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 66,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 240 lpm @ 560 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 900 tonne (1,000 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

191

Case B5A – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 290 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 54 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 29 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 4 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B5A – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.4.7 Case B5A - Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-88 shows a 

detailed breakdown of the capital costs; Exhibit 3-89 shows the owner’s costs, TOC, and TASC; 

Exhibit 3-90 shows the initial and annual O&M costs; and Exhibit 3-91 shows the COE 

breakdown. 

The estimated TPC of the GEE gasifier with no CO2 capture is $2,449/kW. Process contingency 

represents 2.5 percent of the TPC, and project contingency represents 13.5 percent. The COE is 

$102.6/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

192

Exhibit 3-88 Case B5A total plant cost details

Case: B5A – GEE Radiant IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 622 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,435 $0 $2,137 $0 $6,572 $657 $0 $1,446 $8,675 $14

1.2 Coal Stackout & Reclaim $5,731 $0 $1,370 $0 $7,101 $710 $0 $1,562 $9,373 $15

1.3 Coal Conveyors & Yd Crush $5,328 $0 $1,356 $0 $6,684 $668 $0 $1,470 $8,823 $14

1.4 Other Coal Handling $1,394 $0 $314 $0 $1,708 $171 $0 $376 $2,254 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $2,961 $7,739 $0 $10,701 $1,070 $0 $2,354 $14,125 $23

Subtotal $16,887 $2,961 $12,917 $0 $32,765 $3,277 $0 $7,208 $43,250 $70

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/ 2.3 $0 w/ 2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,891 $454 $292 $0 $2,638 $264 $0 $580 $3,482 $6

2.3 Slurry Prep & Feed $25,812 $0 $11,252 $0 $37,064 $3,706 $1,853 $8,525 $51,149 $82

2.4 Misc. Coal Prep & Feed $1,040 $760 $2,238 $0 $4,037 $404 $0 $888 $5,329 $9

2.9 Coal & Sorbent Feed Foundation $0 $3,814 $3,273 $0 $7,087 $709 $0 $1,559 $9,355 $15

Subtotal $28,743 $5,028 $17,055 $0 $50,826 $5,083 $1,853 $11,552 $69,314 $111

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,461 $5,974 $3,132 $0 $12,567 $1,257 $0 $2,765 $16,589 $27

3.2 Water Makeup & Pretreating $758 $78 $416 $0 $1,252 $125 $0 $413 $1,791 $3

3.3 Other Feedwater Subsystems $1,946 $643 $575 $0 $3,164 $316 $0 $696 $4,176 $7

3.4 Service Water Systems $443 $883 $3,045 $0 $4,372 $437 $0 $1,443 $6,251 $10

3.5 Other Boiler Plant Systems $2,388 $892 $2,196 $0 $5,476 $548 $0 $1,205 $7,228 $12

3.6 FO Supply Sys & Nat Gas $17,740 $718 $665 $0 $19,123 $1,912 $0 $4,207 $25,242 $41

3.7 Waste Treatment Equipment $1,025 $0 $635 $0 $1,660 $166 $0 $548 $2,374 $4

3.8 Misc. Power Plant Equipment $1,277 $170 $664 $0 $2,111 $211 $0 $697 $3,019 $5

Subtotal $29,037 $9,360 $11,328 $0 $49,725 $4,972 $0 $11,973 $66,670 $107

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $136,778 $0 $75,333 $0 $212,111 $21,211 $29,509 $40,271 $303,102 $487

4.2 Syngas Cooler w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $195,452 $0 w/equip. $0 $195,452 $19,545 $0 $21,500 $236,496 $380

4.4 Scrubber & LT Heat Recovery $7,080 $5,763 $5,957 $0 $18,800 $1,880 $0 $4,136 $24,816 $40

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Soot Recovery & SARU $2,159 $1,025 $2,013 $0 $5,197 $520 $0 $1,143 $6,860 $11

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $7,429 $6,482 $0 $13,911 $1,391 $0 $3,826 $19,128 $31

Subtotal $341,469 $14,218 $89,784 $0 $445,471 $44,547 $29,509 $70,875 $590,403 $949

5A Gas Cleanup & Piping

5A.1 Single Stage Selexol $50,584 $0 $42,628 $0 $93,212 $9,321 $0 $20,507 $123,040 $198

5A.2 Elemental Sulfur Plant $12,121 $2,363 $15,532 $0 $30,015 $3,002 $0 $6,603 $39,620 $64

5A.3 Mercury Removal $1,515 $0 $1,145 $0 $2,661 $266 $133 $612 $3,672 $6

5A.4 COS Hydrolysis $4,309 $0 $5,589 $0 $9,898 $990 $0 $2,178 $13,066 $21

5A.7 Fuel Gas Piping $0 $882 $577 $0 $1,459 $146 $0 $321 $1,926 $3
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

193

Case: B5A – GEE Radiant IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 622 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.9 HGCU Foundations $0 $798 $538 $0 $1,336 $134 $0 $441 $1,911 $3

Subtotal $68,530 $4,043 $66,009 $0 $138,582 $13,858 $133 $30,662 $183,234 $295

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $104,200 $0 $7,506 $0 $111,706 $11,171 $5,585 $12,846 $141,308 $227

6.2 Syngas Expander $7,146 $0 $981 $0 $8,126 $813 $0 $1,341 $10,280 $17

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $5

Subtotal $111,346 $1,016 $9,662 $0 $122,024 $12,202 $5,585 $14,910 $154,721 $249

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $31,080 $0 $6,019 $0 $37,099 $3,710 $0 $4,081 $44,890 $72

7.3 Ductwork $0 $2,080 $1,458 $0 $3,538 $354 $0 $778 $4,670 $8

7.4 Stack $4,014 $0 $1,498 $0 $5,511 $551 $0 $606 $6,669 $11

7.9 HRSG, Duct & Stack Foundations $0 $764 $767 $0 $1,531 $153 $0 $505 $2,190 $4

Subtotal $35,094 $2,844 $9,741 $0 $47,679 $4,768 $0 $5,971 $58,418 $94

8 Steam Turbine Generator

8.1 Steam TG & Accessories $38,955 $0 $5,979 $0 $44,934 $4,493 $0 $4,943 $54,370 $87

8.2 Turbine Plant Auxiliaries $243 $0 $554 $0 $798 $80 $0 $88 $965 $2

8.3 Condenser & Auxiliaries $3,300 $0 $1,878 $0 $5,178 $518 $0 $570 $6,265 $10

8.4 Steam Piping $15,350 $0 $6,657 $0 $22,006 $2,201 $0 $6,052 $30,258 $49

8.9 TG Foundations $0 $1,147 $2,027 $0 $3,174 $317 $0 $1,047 $4,539 $7

Subtotal $57,848 $1,147 $17,094 $0 $76,089 $7,609 $0 $12,699 $96,397 $155

9 Cooling Water System

9.1 Cooling Towers $4,180 $0 $1,270 $0 $5,450 $545 $0 $899 $6,894 $11

9.2 Circulating Water Pumps $2,012 $0 $146 $0 $2,158 $216 $0 $356 $2,730 $4

9.3 Circ. Water System Auxiliaries $177 $0 $25 $0 $202 $20 $0 $33 $256 $0

9.4 Circ. Water Piping $0 $7,847 $1,901 $0 $9,747 $975 $0 $2,144 $12,867 $21

9.5 Make-up Water System $428 $0 $589 $0 $1,017 $102 $0 $224 $1,342 $2

9.6 Component Cooling Water Sys $897 $1,073 $737 $0 $2,707 $271 $0 $595 $3,573 $6

9.9 Circ. Water System Foundations $0 $2,576 $4,576 $0 $7,152 $715 $0 $2,360 $10,227 $16

Subtotal $7,695 $11,495 $9,243 $0 $28,433 $2,843 $0 $6,612 $37,889 $61

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,251 $7,858 $15,855 $0 $37,965 $3,797 $0 $4,176 $45,938 $74

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $693 $0 $749 $0 $1,442 $144 $0 $238 $1,825 $3

10.7 Ash Transport & Feed Equipment $954 $0 $223 $0 $1,177 $118 $0 $194 $1,489 $2

10.8 Misc. Ash Handling Equipment $1,436 $1,760 $522 $0 $3,718 $372 $0 $613 $4,703 $8

10.9 Ash/Spent Sorbent Foundation $0 $58 $76 $0 $135 $13 $0 $44 $193 $0

Subtotal $17,335 $9,676 $17,426 $0 $44,437 $4,444 $0 $5,266 $54,147 $87

11 Accessory Electric Plant

11.1 Generator Equipment $1,165 $0 $1,134 $0 $2,299 $230 $0 $253 $2,782 $4

11.2 Station Service Equipment $4,601 $0 $423 $0 $5,024 $502 $0 $553 $6,080 $10

11.3 Switchgear & Motor Control $8,493 $0 $1,579 $0 $10,071 $1,007 $0 $1,662 $12,740 $20
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case: B5A – GEE Radiant IGCC w/o CO2 Estimate Type: Conceptual

Plant Size (MW,net): 622 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.4 Conduit & Cable Tray $0 $4,315 $13,302 $0 $17,617 $1,762 $0 $4,845 $24,223 $39

11.5 Wire & Cable $0 $8,320 $5,062 $0 $13,382 $1,338 $0 $3,680 $18,400 $30

11.6 Protective Equipment $0 $805 $2,988 $0 $3,793 $379 $0 $626 $4,798 $8

11.7 Standby Equipment $276 $0 $275 $0 $552 $55 $0 $91 $698 $1

11.8 Main Power Transformers $18,037 $0 $175 $0 $18,211 $1,821 $0 $3,005 $23,037 $37

11.9 Electrical Foundations $0 $183 $498 $0 $680 $68 $0 $225 $973 $2

Subtotal $32,572 $13,623 $25,436 $0 $71,630 $7,163 $0 $14,938 $93,732 $151

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,187 $0 $809 $0 $1,996 $200 $100 $344 $2,640 $4

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $273 $0 $178 $0 $451 $45 $23 $104 $623 $1

12.7 Computer & Accessories $6,332 $0 $207 $0 $6,539 $654 $327 $752 $8,272 $13

12.8 Instrument Wiring & Tubing $0 $2,438 $4,614 $0 $7,052 $705 $353 $2,027 $10,137 $16

12.9 Other I & C Equipment $4,233 $0 $2,097 $0 $6,330 $633 $317 $1,092 $8,372 $13

Subtotal $12,025 $2,438 $7,906 $0 $22,368 $2,237 $1,118 $4,319 $30,043 $48

13 Improvements to Site

13.1 Site Preparation $0 $118 $2,689 $0 $2,807 $281 $0 $926 $4,014 $6

13.2 Site Improvements $0 $2,103 $2,973 $0 $5,077 $508 $0 $1,675 $7,260 $12

13.3 Site Facilities $3,769 $0 $4,231 $0 $8,000 $800 $0 $2,640 $11,440 $18

Subtotal $3,769 $2,222 $9,893 $0 $15,884 $1,588 $0 $5,242 $22,714 $37

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,930 $4,172 $0 $7,102 $710 $0 $1,172 $8,984 $14

14.3 Administration Building $0 $1,013 $734 $0 $1,747 $175 $0 $288 $2,210 $4

14.4 Circulation Water Pumphouse $0 $200 $106 $0 $305 $31 $0 $50 $386 $1

14.5 Water Treatment Buildings $0 $623 $607 $0 $1,230 $123 $0 $203 $1,556 $3

14.6 Machine Shop $0 $518 $354 $0 $873 $87 $0 $144 $1,104 $2

14.7 Warehouse $0 $837 $540 $0 $1,377 $138 $0 $227 $1,742 $3

14.8 Other Buildings & Structures $0 $501 $390 $0 $891 $89 $0 $196 $1,177 $2

14.9 Waste Treating Building & Str. $0 $1,121 $2,140 $0 $3,261 $326 $0 $717 $4,304 $7

Subtotal $0 $8,059 $9,222 $0 $17,282 $1,728 $0 $3,107 $22,117 $36

Total $762,350 $88,130 $312,716 $0 $1,163,195 $116,320 $38,199 $205,336 $1,523,050 $2,449
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-89 Case B5A owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $14,667 $24

1 Month Maintenance Materials $3,346 $5

1 Month Non-fuel Consumables $452 $1

1 Month Waste Disposal $473 $1

25% of 1 Months Fuel Cost at 100% CF $2,920 $5

2% of TPC $30,461 $49

Total $52,318 $84

Inventory Capital

60-day supply of fuel and consumables at 100% CF $23,916 $38

0.5% of TPC (spare parts) $7,615 $12

Total $31,532 $51

Other Costs

Initial Cost for Catalyst and Chemicals $11,013 $18

Land $900 $1

Other Owner's Costs $228,457 $367

Financing Costs $41,122 $66

Total Overnight Costs (TOC) $1,888,393 $3,036

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,152,768 $3,461
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-90 Case B5A initial and annual operating and maintenance costs

Case: B5A – GEE Radiant IGCC w/o CO2 Cost Base: Jun 2011

Plant Size (MW,net): 622 Heat Rate-net (Btu/kWh): 8,758 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 9.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 15.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $6,781,554 $10.904

Maintenance Labor: $16,685,386 $26.828

Administrative & Support Labor: $5,866,735 $9.433

Property Taxes and Insurance: $30,460,991 $48.977

Total: $59,794,666 $96.142

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $32,119,526 $7.36931

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 3,423 $1.67 $0 $1,673,317 $0.38392

Makeup and Waste Water 

Treatment Chemicals (lbs):

0 20,395 $0.27 $0 $1,595,062 $0.36596

Carbon (Mercury Removal) (lb): 92,086 158 $5.50 $506,474 $253,237 $0.05810

COS Catalyst (m3): 422 0.29 $3,751.70 $1,582,971 $316,594 $0.07264

Selexol Solution (gal): 242,554 36 $36.79 $8,923,873 $386,544 $0.08869

Claus Catalyst (ft3): w/equip. 1.94 $203.15 $0 $115,175 $0.02643

Subtotal: $11,013,317 $4,339,929 $0.99573

Waste Disposal

Spent Mercury Catalyst (lb.): 0 158 $0.65 $0 $29,932 $0.00687

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 615 $25.11 $0 $4,507,185 $1.03410

 Subtotal: $0 $4,537,118 $1.04097

By-Products

Sulfur (tons): 0 140 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $11,013,317 $40,996,573 $9.40600

Fuel Cost

Illinois Number 6 (ton): 0 5,603 $68.54 $0 $112,132,176 $25.72691

Total: $0 $112,132,176 $25.72691

Exhibit 3-91 Case B5A COE breakdown

Component Value, $/MWh Percentage

Capital 53.7 52%

Fixed 13.7 13%

Variable 9.4 9%

Fuel 25.7 25%

Total (Excluding T&S) 102.6 N/A

CO2 T&S 0.0 0%

Total (Including T&S) 102.6 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.4.8 Case B5B - GEE Radiant IGCC with CO2 Capture

Case B5B is configured to produce electric power with CO2 capture. The plant configuration is 

the same as Case B5A, namely two gasifier trains, two state-of-the-art 2008 F-class turbines, two 

HRSGs, and one steam turbine. The gross power output from the plant is constrained by the 

capacity of the two CTs, and since the CO2 capture process increases the auxiliary load on the 

plant, the net output is significantly reduced relative to Case B5A.

The process description for Case B5B is similar to Case B5A with several notable exceptions to 

accommodate CO2 capture. A BFD and stream tables for Case B5B are shown in Exhibit 3-92

and Exhibit 3-93, respectively. Instead of repeating the entire process description, only 

differences from Case B5A are reported here.

3.4.8.1 Gasification

The gasification process is the same as Case B5A with the exception that total coal feed to the 

two gasifiers is 5,302 tonnes/day (5,844 tpd) (stream 6) and the ASU provides 4,342 tonnes/day 

(4,786 tpd) of 95 percent oxygen to the gasifier and Claus plant (streams 3 and 5).

3.4.8.2 Raw Gas Cooling/Particulate Removal

Raw gas cooling and particulate removal are the same as Case B5A with the exception that 

approximately 443,118 kg/hr (976,891 lb/hr) of saturated steam at 13.8 MPa (2,000 psia) is 

generated in the radiant SGCs.

3.4.8.3 Syngas Scrubber/Sour Water Stripper

No differences from Case B5A.

3.4.8.4 Sour Gas Shift

The SGS process was described in Section 3.1.3. In Case B5B steam (stream 11) is added to the 

syngas exiting the scrubber to adjust the H2O:CO molar ratio to 2:1 prior to the first SGS reactor. 

The hot syngas exiting the first stage of SGS is used to generate the steam that is added in stream 

11. A second stage of SGS results in 97 percent overall conversion of the CO to CO2. The warm 

syngas from the second stage of SGS (stream 12) is cooled to 236°C (456°F) by preheating the 

unshifted syngas prior to the SGS. The SGS catalyst also serves to hydrolyze COS, thus 

eliminating the need for a separate COS hydrolysis reactor. Following the second SGS cooler,

the syngas is further cooled to 35°C (95°F) prior to the mercury removal beds.

3.4.8.5 Mercury Removal and AGR

Mercury removal is the same as in Case B5A.

The AGR process in Case B5B is a two-stage Selexol process where H2S is removed in the first 

stage and CO2 in the second stage of absorption, as previously described in Section 3.1.5. The 

process results in three product streams: the clean syngas, a CO2-rich stream and an acid gas feed 

to the Claus plant. The acid gas (stream 18) contains 35 percent H2S and 52 percent CO2 with 

the balance primarily N2. The CO2-rich stream is discussed further in the CO2 compression 

section.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-92 Case B5B block flow diagram, GEE IGCC with CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

TURBINE COOLING AIR

QUENCH AND

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

SHIFT

REACTORS

ELEVATED

PRESSURE

ASU

GEE GASIFIER

SECTION

(RADIANT

COOLER)

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

DUAL

STAGE

SELEXOL

UNIT

CLAUS

PLANT

HRSG

AMBIENT AIR

SYNGAS

EXPANDER

HYDROGENATION

REACTOR AND GAS

COOLER

CO2

COMPRESSION

1

5

9

10

11

12 13 14

17

19

20

21

18

6 8

2 3

4

22

23 24

AIR TO ASU

AS-RECEIVED

COAL

SLAG

SHIFT

STEAM

WATER RECYCLE

TO PROCESS

DEMAND

NOTE: WATER FROM TAIL

GAS COOLER MODELED, 

BUT NOT SHOWN

NITROGEN DILUENT

SYNGAS

CLEAN

GAS

CO2

STREAMS

CO2

PRODUCT

SULFUR

TAIL GAS

RECYCLE TO

SELEXOL

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

FLUE GAS

STACK GAS

VENT GAS

CLAUS

PLANT

OXIDANT

2X STATE-OF-THEART F-CLASS

GAS TURBINES

SYNGAS

H/P 

REHEAT

15

16

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

25

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

20

TAIL GAS

RECYCLE FROM

CLAUS PLANT

SLURRY

MIXER

SLURRY 7

WATER
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-93 Case B5B stream table, GEE IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0166 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0068 0.0000 0.0054 0.0071 0.0071

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0009 0.0000 0.0007 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2823 0.0000 0.0060 0.0078 0.0077

CO2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.1089 0.0000 0.3082 0.4019 0.4055

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2689 0.0000 0.4366 0.5692 0.5649

H2O 0.0099 0.1363 0.0000 0.0003 0.0000 0.0000 0.9995 0.0000 0.1369 0.3190 1.0000 0.2325 0.0012 0.0013

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0002 0.0000 0.0001 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0057 0.0000 0.0047 0.0061 0.0061

N2 0.7732 0.7061 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0055 0.0000 0.0044 0.0058 0.0064

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0005 0.0000 0.0019 0.0016 0.0000 0.0013 0.0000 0.0000

O2 0.2074 0.1356 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 27,361 1,650 96 20,050 5,526 0 5,037 0 23,122 29,284 7,193 36,477 27,978 28,367

V-L Flowrate (kg/hr) 789,549 45,326 3,080 562,613 177,826 0 90,747 0 465,238 575,977 129,586 705,563 552,385 564,913

Solids Flowrate (kg/hr) 0 0 0 0 0 220,902 0 24,237 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 142 1,316 677 206 288 240 35 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.55 5.52 5.52 5.41 5.14 5.10

Steam Table Enthalpy (kJ/kg) A 30.23 35.64 26.67 92.50 26.67 --- 537.77 --- 1,428.30 1,066.52 2,917.15 942.88 37.11 36.40

AspenPlus Enthalpy (kJ/kg)B -97.58 -1,492.10 4.13 63.47 4.13 -2,116.95 -15,427.03 -727.24 -5,246.11 -7,406.90 -13,053.16 -8,863.69 -8,084.69 -8,087.64

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 872.0 --- 14.0 27.2 25.6 24.8 40.7 40.9

V-L Molecular Weight 28.857 27.476 32.181 28.060 32.181 --- 18.015 --- 20.121 19.669 18.015 19.343 19.744 19.914

V-L Flowrate (lbmole/hr) 60,320 3,637 211 44,204 12,182 0 11,105 0 50,975 64,560 15,858 80,418 61,680 62,539

V-L Flowrate (lb/hr) 1,740,658 99,926 6,790 1,240,349 392,039 0 200,062 0 1,025,674 1,269,812 285,687 1,555,499 1,217,800 1,245,421

Solids Flowrate (lb/hr) 0 0 0 0 0 487,005 0 53,433 0 0 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 287 2,400 1,250 403 550 463 95 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 805.0 800.0 800.0 785.0 745.0 740.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- 231.2 --- 614.1 458.5 1,254.1 405.4 16.0 15.7

AspenPlus Enthalpy (Btu/lb)B -42.0 -641.5 1.8 27.3 1.8 -910.1 -6,632.4 -312.7 -2,255.4 -3,184.4 -5,611.9 -3,810.7 -3,475.8 -3,477.1

Density (lb/ft3) 0.076 0.091 0.687 1.521 0.687 --- 54.440 --- 0.871 1.699 1.597 1.550 2.544 2.552

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-93 Case B5B stream table, GEE IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0115 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH4 0.0015 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0124 0.0124 0.0124 0.0002 0.0022 0.0000 0.0064 0.0000 0.0000 0.0000 0.0000

CO2 0.0502 0.0502 0.0502 0.9948 0.5214 0.0000 0.6664 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.9139 0.9139 0.9139 0.0048 0.1028 0.0000 0.2562 0.0000 0.0000 0.0000 0.0000

H2O 0.0001 0.0001 0.0001 0.0000 0.0226 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.3477 0.0000 0.0050 0.0000 0.0000 0.0000 0.0000

N2 0.0105 0.0105 0.0105 0.0000 0.0008 0.0000 0.0541 0.7732 0.7541 0.7541 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 17,423 17,423 17,423 10,425 497 0 390 110,253 139,657 139,657 34,514

V-L Flowrate (kg/hr) 90,178 90,178 90,178 456,650 17,683 0 12,529 3,181,557 3,834,349 3,834,349 621,772

Solids Flowrate (kg/hr) 0 0 0 0 0 5,524 0 0 0 0 0

Temperature (°C) 35 241 196 51 48 178 38 15 562 132 534

Pressure (MPa, abs) 5.10 5.07 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 195.53 1,389.05 1,124.24 -162.31 74.87 --- 5.30 30.23 834.76 343.83 3,432.88

AspenPlus Enthalpy (kJ/kg)B -4,051.34 -2,857.82 -3,122.63 -9,120.19 -6,107.59 141.99 -8,217.57 -97.58 -587.80 -1,078.73 -12,537.44

Density (kg/m3) 10.1 6.0 4.2 641.8 2.2 5,280.5 77.9 1.2 0.4 0.9 36.7

V-L Molecular Weight 5.176 5.176 5.176 43.805 35.588 --- 32.150 28.857 27.456 27.456 18.015

V-L Flowrate (lbmole/hr) 38,412 38,412 38,412 22,983 1,095 0 859 243,066 307,891 307,891 76,089

V-L Flowrate (lb/hr) 198,808 198,808 198,808 1,006,740 38,985 0 27,621 7,014,133 8,453,292 8,453,292 1,370,772

Solids Flowrate (lb/hr) 0 0 0 0 0 12,178 0 0 0 0 0

Temperature (°F) 95 465 384 124 119 352 100 59 1,044 270 994

Pressure (psia) 740.0 735.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 84.1 597.2 483.3 -69.8 32.2 --- 2.3 13.0 358.9 147.8 1,475.9

AspenPlus Enthalpy (Btu/lb)B -1,741.8 -1,228.6 -1,342.5 -3,921.0 -2,625.8 61.0 -3,532.9 -42.0 -252.7 -463.8 -5,390.1

Density (lb/ft3) 0.630 0.377 0.260 40.068 0.137 329.649 4.864 0.076 0.026 0.053 2.293

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

201

3.4.8.6 CO2 Compression and Dehydration

CO2 from the AGR process is flashed at three pressure levels to separate CO2 and decrease H2

losses to the CO2 product pipeline. The HP CO2 stream is flashed at 2.0 MPa (289.7 psia), 

compressed, and recycled back to the CO2 absorber. The MP CO2 stream is flashed at 1.0 MPa 

(149.7 psia). The LP CO2 stream is flashed at 0.1 MPa (16.7 psia), compressed to 1.0 MPa 

(149.5 psia), and combined with the MP CO2 stream. The combined stream is compressed from 

2.1 MPa (149.5 psia) to an SC condition at 15.3 MPa (2,215 psia) using a multiple-stage, 

intercooled compressor. During compression, the CO2 stream is dehydrated to a dew point

of -40oC (-40°F) with triethylene glycol. The raw CO2 stream from the Selexol process contains 

over 99 percent CO2. The CO2 (stream 17) is transported to the plant fence line and is 

sequestration ready. CO2 T&S costs were estimated using the methodology described in Section

2.6.

3.4.8.7 Claus Unit

The Claus plant is the same as Case B5A with the following exceptions:

• 5,528 kg/hr (12,178 lb/hr) of sulfur (stream 19) are produced

• The waste heat boiler generates 13,555 kg/hr (29,884 lb/hr) of 4.0 MPa (575 psia) steam 

of which 12,679 kg/hr (27,953 lb/hr) is available to the medium pressure steam header

3.4.8.8 Power Block

Clean syngas from the AGR plant is heated to 241°C (465°F) using HP BFW before passing 

through an expansion turbine. The clean syngas (stream 16) is diluted with nitrogen (stream 4) 

and then enters the CT burner. There is no integration between the CT and the ASU in this case. 

The exhaust gas (stream 22) exits the CT at 562°C (1,044°F) and enters the HRSG where 

additional heat is recovered. The flue gas exits the HRSG at 132°C (270°F) (stream 23) and is 

discharged through the plant stack. The steam raised in the HRSG is used to power an advanced 

commercially available steam turbine using a 12.4 MPa/534°C/534°C (1,800 psig/994°F/994°F) 

steam cycle.

3.4.8.9 Air Separation Unit (ASU)

The same elevated pressure ASU is used in Case B5B and produces 4,342 tonnes/day (4,786 tpd) 

of 95 mol% oxygen and 14,591 tonnes/day (16,084 tpd) of nitrogen. There is no integration 

between the ASU and the CT in the CO2 capture case.

3.4.9 Case B5B - Performance Results

The Case B5B modeling assumptions were presented previously in Section 3.4.3.

The plant produces a net output of 543 MW at a net plant efficiency of 32.6 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-94; Exhibit 3-95

provides a detailed breakdown of the auxiliary power requirements. The ASU accounts for 

nearly 60 percent of the auxiliary load between the main air compressor, nitrogen compressor, 

oxygen compressor, and ASU auxiliaries. The two-stage Selexol process and CO2 compression 

account for an additional 26 percent of the auxiliary power load. The BFW pumps and cooling 

water system (CWPs and cooling tower fan) compose over 6 percent of the load, leaving 8 

percent of the auxiliary load for all other systems.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

202

Exhibit 3-94 Case B5B plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 264

Total Gross Power, MWe 734

Air Separation Unit Main Air Compressor, kWe 67,330

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,640

CO2 Compression, kWe 31,160

Acid Gas Removal, kWe 19,230

Balance of Plant, kWe 26,870

Total Auxiliaries, MWe 191

Net Power, MWe 543

HHV Net Plant Efficiency (%) 32.6%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,034 (10,459)

HHV Cold Gas Efficiency, % 79.2%

HHV Combustion Turbine Efficiency, % 36.0%

LHV Net Plant Efficiency (%) 33.8%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 10,643 (10,087)

LHV Cold Gas Efficiency, % 75.9%

LHV Combustion Turbine Efficiency, % 42.4%

Steam Turbine Cycle Efficiency, % 42.4%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 8,496 (8,053)

Condenser Duty, GJ/hr (MMBtu/hr) 1,513 (1,434)

As-Received Coal Feed, kg/hr (lb/hr) 220,902 (487,005)

HHV Thermal Input, kWt 1,665,056

LHV Thermal Input, kWt 1,605,967

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.041 (10.7)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.033 (8.8)

O2:Coal 0.761
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

203

Exhibit 3-95 Case B5B plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 264

Total Gross Power, MWe 734

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,270

Sour Water Recycle Slurry Pump, kWe 190

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 67,330

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,640

Feedwater Pumps, kWe 4,180

Quench Water Pump, kWe 540

Syngas Recycle Compressor, kWe 0

CO2 Compression, kWe 31,160

Scrubber Pumps, kWe 230

Acid Gas Removal, kWe 19,230

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 280

Circulating Water Pumps, kWe 4,630

Ground Water Pumps, kWe 530

Cooling Tower Fans, kWe 2,400

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,780

Miscellaneous Balance of PlantA,B, kWe 3,000

Transformer Losses, kWe 2,860

Total Auxiliaries, MWe 191

Net Power, MWe 543

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

204

3.4.9.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in Section 

2.4. A summary of the plant air emissions for Case B5B is presented in Exhibit 3-96. All HCl is 

assumed to be removed and is, therefore, not reported.

Exhibit 3-96 Case B5B air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.001 (0.002) 39 (43) 0.008 (0.017)

NOx 0.021 (0.049) 878 (967) 0.171 (0.376)

Particulates 0.003 (0.0071) 128 (141) 0.025 (0.055)

Hg 1.67E-7 (3.88E-7) 0.007 (0.008) 1.36E-6 (3.00E-6)

CO2 8 (20) 355,435 (391,800) 69 (152)

CO2C - - 93 (206)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the two-stage 

Selexol AGR process. As a result of achieving the 90 percent CO2 removal target, the sulfur 

compounds are removed to an extent that exceeds the environmental target in Section 2.3. The 

clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This 

results in a concentration in the flue gas of less than 1 ppmv. The H2S-rich regeneration gas 

from the AGR system is fed to a Claus plant, producing elemental sulfur. The Claus plant tail 

gas is hydrogenated to convert all sulfur species to H2S and then recycled back to the Selexol 

process, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution to 15 ppmvd (as NO2 @15 percent O2). 

Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR 

process. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

Ninety two percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall carbon 

removal is 90.0 percent.

The carbon balance for the plant is shown in Exhibit 3-97. The carbon input to the plant consists 

of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as unburned carbon 

in the slag and as CO2 in the stack gas, ASU vent gas, and the captured CO2 product. The carbon 

capture efficiency is defined as one minus the amount of carbon in the stack gas relative to the 

total carbon in less carbon contained in the slag, represented by the following fraction: 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

205

CCCCCCCCCC SS SSSS

(TT TT CCCCCCCCCC ) − (CCCCCCCCCC SS SS) = �1 − � 30,516

311,631 − 6,209� ∗� 100 = 90.0%

Exhibit 3-97 Case B5B carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,813 (310,440) Stack Gas 13,842 (30,516)

Air (CO2) 540 (1,191) CO2 Product 124,589 (274,672)

ASU Vent 107 (237)

Slag 2,816 (6,209)

Total 141,353 (311,631) Total 141,353 (311,631)

Exhibit 3-98 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur in 

the coal. Sulfur output includes the sulfur recovered in the Claus plant and sulfur emitted in the 

stack gas. Sulfur in the slag is considered to be negligible.

Exhibit 3-98 Case B5B sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,537 (12,206) Stack Gas 3 (6)

CO2 Product 10 (23)

Elemental Sulfur 5,524 (12,178)

Total 5,537 (12,206) Total 5,537 (12,206)

Exhibit 3-99 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for cases B1A-B5A.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

206

Exhibit 3-99 Case B5B water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.53 (139) 0.53 (139) – – –

Slurry Water 1.51 (400) 1.51 (400) – – –

Quench/Wash 2.86 (757) 0.72 (191) 2.14 (566) – 2.14 (566)

Humidifier – – – – –

SWS Blowdown – – – 0.03 (7.30) -0.03 (-7.30)

Condenser Makeup 2.37 (627) – 2.37 (627) – 2.37 (627)

 BFW Makeup 0.21 (56) – 0.21 (56) – 0.21 (56)

 Gasifier Steam – – – – –

 Shift Steam 2.16 (571) – 2.16 (571) – 2.16 (571)

 CT Steam Dilution – – – – –

Cooling Tower 18.06 

(4,770) 0.49 (129) 17.57 (4,641) 4.06 (1,073) 13.51 (3,568)

 BFW Blowdown – 0.21 (56) -0.21 (-56) – -0.21 (-56)

 SWS Blowdown – 0.28 (72.96) -0.28 (-

72.96) – -0.28 (-72.96)

Total 25.33 

(6,692) 3.25 (858) 22.08 (5,834) 4.09 (1,080) 18.00 (4,754)

3.4.9.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-100

through Exhibit 3-102:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is presented in tabular form in Exhibit 3-103. The power out is 

the combined CT, steam turbine, and expander power prior to generator losses. The power at the 

generator terminals (shown in Exhibit 3-94) is calculated by multiplying the power out by a 

combined generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

207

Exhibit 3-100 Case B5B coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B

GEE GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-B5B-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

1,740,658 W

59 T

15 P

13 H

392,039 W

90 T

125 P

11 H

392,039 W

241 T

940 P

41 H

To Claus Plant

6,790 W

90 T

125 P

11 H

99,926 W

65 T

16 P

15 H

1,083,575 W

90 T

56 P

14 H

156,775 W

50 T

182 P

3 H

5

1

3

2

Slurry Mix 

Tank

Slag

487,005 W

59 T

15 P

200,062 W

287 T

840 P

231 H

53,433 W

2,400 T

815 P

676,490 W

385 T

384 P

87 H

687,067 W

156 T

840 P

1,739,104 W

100 T

190 P

18 H

6

676,490 W

199 T

384 P

40 H

N2 Boost

Compressor 563,859 W

199 T

384 P

40 H

563,859 W

385 T

469 P

87 H

GE Energy 

Gasifier

Radiant

Syngas

Cooler

Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

1,025,674 W

1,250 T

805 P

612 H

1,269,812 W

403 T

800 P

458 H

Syngas

Quench

1,403,971 W

450 T

805 P

536 H

8

9

10

378,297 W

371 T

1,200 P

329 H

From Sour

Water Stripper

To Fuel Gas 

Preheater

From Fuel Gas 

Preheater

386,894 W

403 T

800 P

419 H

386,894 W

150 T

1,205 P

118 H

To Sour

Water Stripper

69,404 W

286 T

115 P

228 H

7

N2 to GT Combustor

N2 to GT Combustor

Raw Fuel Gas

From HP 

Economizer 2

To HP Economizer 1

To Superheater

From HP 

Economizer 2

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,459 Btu/kWh

Milled Coal

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

208

Exhibit 3-101 Case B5B syngas cleanup heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B

GEE GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-B5B-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

2 OF 3

Mercury 

Removal

Knock

Out

Drum

Sour

Drum

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

Syngas

Coolers

Sour

Stripper

1,269,812 W

403 T

800 P

458 H

1,245,421 W

95 T

740 P

16 H

38,985 W

119 T

24 P

32 H

198,808 W

384 T

460 P

483 H

12,178 W

36,092 W

450 T

12 P

458 H

2,495 W

239 T

65 P

442 H

19

13

20

36,092 W

550 T

11 P

419 H

1,217,800 W

95 T

745 P

16 H

8,470 W

114 T

11 P

40 H

27,621 W

100 T

800 P

2 H

15

198,808 W

95 T

740 P

84 H

18

Fuel Gas

Expander

16

198,808 W

465 T

735 P

597 H

High

Temperature

Shift #1

Low 

Temperature

Shift #2

12

11

1,269,812 W

413 T

795 P

450 H

285,687 W

550 T

800 P

1,246 H

1,555,499 W

436 T

795 P

598 H

1,555,499 W

776 T

795 P

582 H

1,555,499 W

400 T

795 P

408 H

1,555,499 W

463 T

785 P

405 H

1,555,499 W

456 T

780 P

402 H

Two-Stage

Selexol

Clean 

Gas

CO2

Acid 

Gas

Multistage 

Intercooled CO2

Compressor

Interstage Knockout

17

10

14

1,006,740 W

124 T

2,215 P

-70 H

Tail Gas Recycle

Compressor

Hydrogenation 

and Tail Gas 

Cooling

From IP 

BFW

To Reheater 

and Shift Steam

From IP BFW, 

LP BFW, and 

Tail Gas Cooling

647,763 W

From Syngas 

Scrubber

To Coal Slurry, Syngas Quench, and Slag Quench

To Water 

Treatment

Makeup Water

Raw Syngas

COS 

Hydrolysis 

Preheater

Reboiler

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas 

Scrubber and HP 

Economizer 1

Fuel Gas 

Preheater Fuel Gas to CT

3

6,790 W

90 T

125 P

11 H

6,790 W

450 T

125 P

92 H

To 

Deaerator

From IP 

BFW

Claus 

Oxygen 

Preheater

From Gland Steam 

Condenser To Syngas 

Cooling

109 T

CO2 Product

To LP Turbine, Preheater

WGS/Gasifier Steam 

and Reheater 

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,459 Btu/kWh

Shift Steam

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

209

Exhibit 3-102 Case B5B combined-cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B5B-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Condensate

Pumps

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,875,814 W

101 T

1 P

69 H

8,453,292 W

270 T

15 P

148 H

198,808 W

384 T

460 P

483 H

1,370,772 W

994 T

1,815 P

1,468 H

10,302 W

298 T

65 P

1,171 H

1,550,148 W

475 T

65 P

1,262 H

1,875,814 W

103 T

120 P

71 H

1,400 W

615 T

65 P

1,331 H

1,400 W

212 T

15 P

180 H

21

24

16

23

Hot Well

Condenser

Make-up

313,504 W

59 T

15 P

27 H

9,026 W

660 T

501 P

1,327 H

9,761 W

615 T

65 P

1,331 H

798 W

994 T

1,815 P

1,468 H

1,337 W

505 T

65 P

1,277 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas 

Cooler HP BFW to 

Radiant 

Syngas Cooler

From Radiant Syngas 

Cooler

To ASU and Fuel 

Gas Preheater

Deaerator

HP Pump

IP Pump

LP 

Evaporator

IP to Syngas and 

WGS Coolers

WGS Shift 

Steam

From Claus, Process Extraction, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown

LP To Syngas 

Coolers

Cold Reheat

Hot Reheat

8,453,292 W

1,044 T

15 P

359 H 22

To WWT

Process 

Extraction

LP Pump

LP From 

Syngas Coolers

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

235 T

274 T

1,857,220 W

274 T

45 P

242 H

1,398,890 W

279 T

2,251 P

247 H

9,286 W

274 T

79 P

242 H

6,109 W

274 T

79 P

242 H 294,721 W

274 T

79 P

242 H 39,399 W

276 T

615 P

244 H

397,467 W

351 T

2,251 P

319 H

305 T 585 T 636 T

28,833 W

585 T

2,001 P

585 H

285,687 W

550 T

805 P

1,221 H

550 T

636 T

976,880 W

585 T

2,001 P

585 H

1,342,123 W

661 T

501 P

1,327 H

397,467 W

585 T

2,001 P

585 H

303,963 W

298 T

65 P

266 H

195 T

224,565 W

298 T

65 P

1,171 H

148,214 W

298 T

65 P

1,171 H

293,460 W

276 T

820 P

244 H

1,000 W

994 T

1,815 P

1,468 H

1,000 W

212 T

15 P

180 H

40,696 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

Condensate to Tail 

Gas Cooling

676,490 W

385 T

469 P

87 H

Nitrogen Diluent

Fuel Gas

Ambient Air

7,773 W

550 T

805 P

1,221 H

IP From Syngas and WGS 

Coolers

994 T

298 T

From ASU and Fuel 

Gas Preheater

Nitrogen Diluent

563,859 W

385 T

384 P

87 H

Blowdown 

Flash

Gross Plant Power: 734 MWe

Auxiliary Load: 191 MWe

Net Plant Power: 543 MWe

Net Plant Efficiency, HHV: 32.6%

Net Plant Heat Rate: 10,459 Btu/kWh

To Claus

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

211

Exhibit 3-103 Case B5B overall energy balance (0°C [32°F] reference)

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,994 

(5,681)

5.0 (4.7) – 5,999 

(5,686)

Air – 120.0 (113.8) – 120.0 

(113.8)

Raw Water Makeup – 83.0 (78.7) – 83.0 (78.7)

Auxiliary Power – – 687 (651) 687 (651)

TOTAL 5,994 

(5,681)

208.1 (197.2) 687 (651) 6,889 

(6,530)

Heat Out (GJ/hr)

ASU Vent – 1.6 (1.5) – 1.6 (1.5)

Slag 92.3 (87.5) 37.8 (35.9) – 130.2 

(123.4)

Stack Gas – 1,318 (1,250) – 1,318 

(1,250)

Sulfur 51.2 (48.5) 0.6 (0.6) – 51.8 (49.1)

Motor Losses and Design 

Allowances

– – 60.1 (57.0) 60.1 (57.0)

Condenser – 1,513 (1,434) – 1,513 

(1,434)

Non-Condenser Cooling Tower 

Loads

– 668 (633) – 668 (633)

CO2 – -74.1 (-70.2) – -74.1 (-70.2)

Blowdown – 43.3 (41.0) – 43.3 (41.0)

CO2 Capture Losses – 176.4 (167.2) – 176.4 

(167.2)

Ambient LossesA – 162.4 (154.0) – 162.4 

(154.0)

Power – – 2,643 

(2,505)

2,643 

(2,505)

TOTAL 143.5 

(136.0)

3,848 (3,647) 2,703 

(2,562)

6,694 

(6,345)

Unaccounted EnergyB – 195 (185) – 195 (185)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

3.4.10 Case B5B - Major Equipment List

Major equipment items for the GEE gasifier with CO2 capture are shown in the following tables. 

The accounts used in the equipment list correspond to the account numbers used in the cost 

estimates in Section 3.4.11. In general, the design conditions include a 10 percent contingency 

for flows and heat duties and a 21 percent contingency for heads on pumps and fans.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

212

Case B5B – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 800 tonne (900 ton) 3 0

Case B5B – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with 

Agitator Field erected 299,900 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 392,320 liters (103,640 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,176,900 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,300 lpm (900 gpm) 2 2

Case B5B – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 1,094,000 liters (289,000 gal) 2 0

2 Condensate Pumps Vertical canned 7,850 lpm @ 90 m H2O

(2,070 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 546,000 kg/hr (1,205,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

8,030 lpm @ 30 m H2O

(2,120 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

6,050 lpm @ 1,800 m H2O 

(1,600 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal

IP water: 1,720 lpm @ 220 m 

H2O (450 gpm @ 730 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

213

Equipment 

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 368 GJ/hr (348 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 131,900 lpm @ 20 m H2O(34,800 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

5,730 lpm @ 20 m H2O

(1,510 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

2,870 lpm @ 270 m H2O 

(760 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

3,350 lpm @ 50 m H2O

(890 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 1,610,000 liter (425,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 1,490 lpm (390 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B5B – Account 4: Gasifier, ASU, and Accessories Including Low Temperature Heat 

Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,900 tonne/day, 5.6 MPa

(3,200 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

256,000 kg/hr (564,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 350,000 kg/hr (772,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 388,000 kg/hr (856,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

304,000 kg/hr, 35°C, 5.2 MPa

(671,000 lb/hr, 95°F, 750 psia) 2 0

6 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

350,000 kg/hr 

(772,000 lb/hr) syngas 2 0

7 ASU Main Air 

Compressor Centrifugal, multi-stage 6,000 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0

8 Cold Box Vendor design 2,400 tonne/day (2,600 tpd) 

of 95% purity oxygen 2 0

9 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (42,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

10 Primary Nitrogen 

Compressor Centrifugal, multi-stage

4,000 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0

11 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

550 m3/min (19,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

214

Equipment 

No. Description Type Design Condition Operating Qty. Spares

12

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

2,000 m3/min (70,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0

Case B5B – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 304,000 kg/hr (670,000 lb/hr),

35°C (95°F), 5.1 MPa (745 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 304,000 kg/hr (670,000 lb/hr),

35°C (95°F), 5.1 MPa (745 psia) 2 0

3 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

4 Water Gas Shift 

Reactors Fixed bed, catalytic 194,000 kg/hr (428,000 lb/hr),227°C (440°F), 5.4 MPa (790 psia) 4 0

5

Shift Reactor Heat 

Recovery 

Exchangers

Shell and Tube

Exchanger 1: 157 GJ/hr (149 

MMBtu/hr) 

Exchanger 2: 3 GJ/hr (3 MMBtu/hr) 

4 0

6 Acid Gas Removal 

Plant Two-stage Selexol 311,000 kg/hr (685,000 lb/hr),35°C (95°F), 5.1 MPa (740 psia) 2 0

7 Hydrogenation 

Reactor Fixed bed, catalytic

18,000 kg/hr (40,000 lb/hr),

232°C (450°F), 0.1 MPa (12.3

psia)

1 0

8 Tail Gas Recycle 

Compressor Centrifugal 14,000 kg/hr (30,000 lb/hr) each 1 0

9 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

1,100 m3/min @ 15.3 MPa (40,000 

scfm @ 2,215 psia) 4 0

Case B5B – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

49,600 kg/h (109,300 lb/h)

5.1 MPa (735 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0

Case B5B – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type

409SS liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 341,975 kg/hr, 

12.4 MPa/534°C 

(753,925 lb/hr, 1,800 psig/994°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

215

Case B5B – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

277 MW

12.4 MPa/534°C/534°C (1,800 psig/ 

994°F/994°F)

1 0

2

Steam

Turbine 

Generator

Hydrogen cooled, static 

excitation

310 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,660GJ/hr (1,580 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B5B – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 465,000 lpm @ 30 m(123,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,590 GJ/hr (2,460 MMBtu/hr) heat duty

1 0

Case B5B – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 254,000 liters (67,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 153,000 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 69,000 liters (18,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 217,000 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 60 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 69,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 250 lpm @ 560 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 1,000 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

216

Case B5B – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 48 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B5B – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.4.11 Case B5B - Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-104 shows 

a detailed breakdown of the capital costs; Exhibit 3-105 shows the owner’s costs, TOC, and 

TASC; Exhibit 3-106 shows the initial and annual O&M costs; and Exhibit 3-107 shows 

the COE breakdown. 

The estimated TPC of the GEE gasifier with CO2 capture is $3,387/kW. Process contingency 

represents 4.2 percent of the TPC, and project contingency represents 13.8 percent. The COE, 

including CO2 T&S costs of $9.2/MWh, is $144.7/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

217

Exhibit 3-104 Case B5B total plant cost details

Case: B5B – GEE Radiant IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,552 $0 $2,194 $0 $6,746 $675 $0 $1,484 $8,905 $16

1.2 Coal Stackout & Reclaim $5,882 $0 $1,407 $0 $7,289 $729 $0 $1,604 $9,621 $18

1.3 Coal Conveyors & Yd Crush $5,469 $0 $1,392 $0 $6,861 $686 $0 $1,509 $9,056 $17

1.4 Other Coal Handling $1,431 $0 $322 $0 $1,753 $175 $0 $386 $2,314 $4

1.9 Coal & Sorbent Hnd. Foundations $0 $3,040 $7,944 $0 $10,984 $1,098 $0 $2,417 $14,499 $27

Subtotal $17,335 $3,040 $13,259 $0 $33,633 $3,363 $0 $7,399 $44,396 $82

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,944 $467 $301 $0 $2,712 $271 $0 $597 $3,580 $7

2.3 Slurry Prep & Feed $26,551 $0 $11,574 $0 $38,125 $3,812 $1,906 $8,769 $52,612 $97

2.4 Misc. Coal Prep & Feed $1,069 $781 $2,301 $0 $4,151 $415 $0 $913 $5,479 $10

2.9 Coal & Sorbent Feed Foundation $0 $3,922 $3,365 $0 $7,287 $729 $0 $1,603 $9,619 $18

Subtotal $29,564 $5,170 $17,541 $0 $52,275 $5,227 $1,906 $11,882 $71,290 $131

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $3,381 $5,835 $3,059 $0 $12,275 $1,227 $0 $2,700 $16,203 $30

3.2 Water Makeup & Pretreating $876 $91 $481 $0 $1,448 $145 $0 $478 $2,071 $4

3.3 Other Feedwater Subsystems $1,901 $628 $561 $0 $3,090 $309 $0 $680 $4,079 $8

3.4 Service Water Systems $512 $1,022 $3,521 $0 $5,055 $505 $0 $1,668 $7,228 $13

3.5 Other Boiler Plant Systems $2,761 $1,032 $2,539 $0 $6,331 $633 $0 $1,393 $8,358 $15

3.6 FO Supply Sys & Nat Gas $17,735 $710 $658 $0 $19,104 $1,910 $0 $4,203 $25,217 $46

3.7 Waste Treatment Equipment $1,185 $0 $734 $0 $1,919 $192 $0 $633 $2,745 $5

3.8 Misc. Power Plant Equipment $1,326 $177 $689 $0 $2,193 $219 $0 $724 $3,135 $6

Subtotal $29,677 $9,494 $12,243 $0 $51,415 $5,142 $0 $12,479 $69,035 $127

4 Gasifier & Accessories

4.1 Syngas Cooler Gasifier System $140,246 $0 $77,258 $0 $217,504 $21,750 $30,249 $41,297 $310,800 $572

4.2 Syngas Cooler w/4.1 $0 w/ 4.1 $0 $0 $0 $0 $0 $0 $0

4.3 ASU & Oxidant Compression $234,789 $0 w/equip. $0 $234,789 $23,479 $0 $25,827 $284,094 $523

4.4 Scrubber & LT Heat Recovery $7,292 $5,935 $6,135 $0 $19,363 $1,936 $0 $4,260 $25,560 $47

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.6 Soot Recovery & SARU $2,224 $1,056 $2,073 $0 $5,353 $535 $0 $1,178 $7,066 $13

4.8 Major Component Rigging w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $7,429 $6,482 $0 $13,911 $1,391 $0 $3,826 $19,128 $35

Subtotal $384,551 $14,421 $91,949 $0 $490,920 $49,092 $30,249 $76,387 $646,648 $1,190

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $160,990 $0 w/equip. $0 $160,990 $16,099 $32,198 $41,857 $251,145 $462

5A.2 Elemental Sulfur Plant $12,451 $2,427 $15,954 $0 $30,833 $3,083 $0 $6,783 $40,699 $75

5A.3 Mercury Removal $1,973 $0 $1,491 $0 $3,464 $346 $173 $797 $4,780 $9

5A.4 Shift Reactors $11,566 $0 $4,624 $0 $16,190 $1,619 $0 $3,562 $21,370 $39

5A.7 Fuel Gas Piping $0 $812 $531 $0 $1,344 $134 $0 $296 $1,774 $3
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

218

Case: B5B – GEE Radiant IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5A.9 HGCU Foundations $0 $735 $495 $0 $1,231 $123 $0 $406 $1,760 $3

Subtotal $186,980 $3,974 $23,096 $0 $214,051 $21,405 $32,371 $53,701 $321,528 $592

5B CO2 Compression

5B.2 CO2 Compression & Drying $40,237 $6,036 $17,430 $0 $63,703 $6,370 $0 $14,015 $84,088 $155

Subtotal $40,237 $6,036 $17,430 $0 $63,703 $6,370 $0 $14,015 $84,088 $155

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $289

6.2 Syngas Expander $6,691 $0 $918 $0 $7,609 $761 $0 $1,256 $9,626 $18

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $6

Subtotal $117,901 $1,016 $9,975 $0 $128,892 $12,889 $11,909 $16,270 $169,960 $313

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,560 $0 $5,723 $0 $35,283 $3,528 $0 $3,881 $42,693 $79

7.3 Ductwork $0 $2,109 $1,478 $0 $3,587 $359 $0 $789 $4,735 $9

7.4 Stack $4,070 $0 $1,519 $0 $5,589 $559 $0 $615 $6,762 $12

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,553 $155 $0 $512 $2,220 $4

Subtotal $33,630 $2,884 $9,498 $0 $46,012 $4,601 $0 $5,797 $56,411 $104

8 Steam Turbine Generator

8.1 Steam TG & Accessories $37,100 $0 $5,758 $0 $42,858 $4,286 $0 $4,714 $51,858 $95

8.2 Turbine Plant Auxiliaries $235 $0 $535 $0 $771 $77 $0 $85 $932 $2

8.3 Condenser & Auxiliaries $3,290 $0 $1,868 $0 $5,158 $516 $0 $567 $6,241 $11

8.4 Steam Piping $15,068 $0 $6,534 $0 $21,602 $2,160 $0 $5,941 $29,703 $55

8.9 TG Foundations $0 $1,108 $1,958 $0 $3,067 $307 $0 $1,012 $4,385 $8

Subtotal $55,693 $1,108 $16,654 $0 $73,456 $7,346 $0 $12,319 $93,121 $171

9 Cooling Water System

9.1 Cooling Towers $4,490 $0 $1,360 $0 $5,850 $585 $0 $965 $7,400 $14

9.2 Circulating Water Pumps $2,175 $0 $163 $0 $2,338 $234 $0 $386 $2,957 $5

9.3 Circ. Water System Auxiliaries $189 $0 $27 $0 $216 $22 $0 $36 $273 $1

9.4 Circ. Water Piping $0 $8,386 $2,031 $0 $10,417 $1,042 $0 $2,292 $13,751 $25

9.5 Make-up Water System $484 $0 $665 $0 $1,150 $115 $0 $253 $1,517 $3

9.6 Component Cooling Water Sys $959 $1,147 $787 $0 $2,893 $289 $0 $636 $3,818 $7

9.9 Circ. Water System Foundations $0 $2,738 $4,866 $0 $7,604 $760 $0 $2,509 $10,874 $20

Subtotal $8,296 $12,271 $9,900 $0 $30,467 $3,047 $0 $7,077 $40,591 $75

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,630 $8,067 $16,277 $0 $38,975 $3,897 $0 $4,287 $47,159 $87

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $710 $0 $767 $0 $1,476 $148 $0 $244 $1,868 $3

10.7 Ash Transport & Feed Equipment $977 $0 $228 $0 $1,205 $120 $0 $199 $1,524 $3

10.8 Misc. Ash Handling Equipment $1,470 $1,801 $534 $0 $3,806 $381 $0 $628 $4,814 $9

10.9 Ash/Spent Sorbent Foundation $0 $60 $78 $0 $138 $14 $0 $46 $197 $0

Subtotal $17,787 $9,928 $17,885 $0 $45,600 $4,560 $0 $5,403 $55,563 $102

11 Accessory Electric Plant
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Case: B5B – GEE Radiant IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 543 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.1 Generator Equipment $1,152 $0 $1,122 $0 $2,274 $227 $0 $250 $2,752 $5

11.2 Station Service Equipment $5,513 $0 $507 $0 $6,020 $602 $0 $662 $7,285 $13

11.3 Switchgear & Motor Control $10,176 $0 $1,891 $0 $12,068 $1,207 $0 $1,991 $15,266 $28

11.4 Conduit & Cable Tray $0 $5,170 $15,938 $0 $21,109 $2,111 $0 $5,805 $29,024 $53

11.5 Wire & Cable $0 $9,969 $6,065 $0 $16,034 $1,603 $0 $4,409 $22,047 $41

11.6 Protective Equipment $0 $806 $2,995 $0 $3,801 $380 $0 $627 $4,808 $9

11.7 Standby Equipment $274 $0 $273 $0 $547 $55 $0 $90 $692 $1

11.8 Main Power Transformers $19,599 $0 $172 $0 $19,771 $1,977 $0 $3,262 $25,011 $46

11.9 Electrical Foundations $0 $180 $491 $0 $672 $67 $0 $222 $961 $2

Subtotal $36,715 $16,126 $29,455 $0 $82,297 $8,230 $0 $17,319 $107,845 $199

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,321 $0 $900 $0 $2,221 $222 $111 $383 $2,937 $5

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $304 $0 $199 $0 $502 $50 $25 $116 $693 $1

12.7 Computer & Accessories $7,046 $0 $230 $0 $7,277 $728 $364 $837 $9,205 $17

12.8 Instrument Wiring & Tubing $0 $2,713 $5,135 $0 $7,847 $785 $392 $2,256 $11,280 $21

12.9 Other I & C Equipment $4,710 $0 $2,334 $0 $7,044 $704 $352 $1,215 $9,316 $17

Subtotal $13,381 $2,713 $8,797 $0 $24,891 $2,489 $1,245 $4,807 $33,431 $62

13 Improvements to Site

13.1 Site Preparation $0 $123 $2,799 $0 $2,922 $292 $0 $964 $4,178 $8

13.2 Site Improvements $0 $2,189 $3,095 $0 $5,284 $528 $0 $1,744 $7,556 $14

13.3 Site Facilities $3,923 $0 $4,404 $0 $8,327 $833 $0 $2,748 $11,907 $22

Subtotal $3,923 $2,312 $10,297 $0 $16,532 $1,653 $0 $5,456 $23,641 $44

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,849 $4,056 $0 $6,904 $690 $0 $1,139 $8,734 $16

14.3 Administration Building $0 $1,057 $766 $0 $1,823 $182 $0 $301 $2,306 $4

14.4 Circulation Water Pumphouse $0 $198 $105 $0 $303 $30 $0 $50 $384 $1

14.5 Water Treatment Buildings $0 $720 $702 $0 $1,422 $142 $0 $235 $1,799 $3

14.6 Machine Shop $0 $541 $370 $0 $911 $91 $0 $150 $1,152 $2

14.7 Warehouse $0 $873 $563 $0 $1,437 $144 $0 $237 $1,818 $3

14.8 Other Buildings & Structures $0 $523 $407 $0 $930 $93 $0 $205 $1,228 $2

14.9 Waste Treating Building & Str. $0 $1,169 $2,233 $0 $3,403 $340 $0 $749 $4,492 $8

Subtotal $0 $8,248 $9,382 $0 $17,630 $1,763 $0 $3,175 $22,568 $42

Total $975,671 $98,741 $297,361 $0 $1,371,773 $137,177 $77,680 $253,485 $1,840,115 $3,387
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-105 Case B5B owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $16,298 $30

1 Month Maintenance Materials $3,682 $7

1 Month Non-fuel Consumables $676 $1

1 Month Waste Disposal $494 $1

25% of 1 Months Fuel Cost at 100% CF $3,046 $6

2% of TPC $36,802 $68

Total $60,998 $112

Inventory Capital

60-day supply of fuel and consumables at 100% CF $25,290 $47

0.5% of TPC (spare parts) $9,201 $17

Total $34,491 $63

Other Costs

Initial Cost for Catalyst and Chemicals $16,548 $30

Land $900 $2

Other Owner's Costs $276,017 $508

Financing Costs $49,683 $91

Total Overnight Costs (TOC) $2,278,752 $4,195

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,597,777 $4,782
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-106 Case B5B initial and annual operating and maintenance costs

Case: B5B – GEE Radiant IGCC w/ CO2 Cost Base: Jun 2011

Plant Size (MW,net): 543 Heat Rate-net (Btu/kWh): 10,459 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 10.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 16.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,233,658 $13.316

Maintenance Labor: $18,843,231 $34.687

Administrative & Support Labor: $6,519,222 $12.001

Property Taxes and Insurance: $36,802,296 $67.747

Total: $69,398,406 $127.751

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $35,348,580 $9.28526

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 4,201 $1.67 $0 $2,053,253 $0.53934

Makeup and Waste Water 

Treatment Chemicals (lbs): 0 25,026 $0.27 $0 $1,957,230 $0.51412

Carbon (Mercury Removal) (lb): 135,182 231 $5.50 $743,501 $371,751 $0.09765

Shift Catalyst (ft3): 6,246 4.28 $771.99 $4,822,025 $964,405 $0.25333

Selexol Solution (gal): 298,498 95 $36.79 $10,982,126 $1,020,094 $0.26796

Claus Catalyst (ft3): w/equip 2.01 $203.15 $0 $119,487 $0.03139

Subtotal: $16,547,652 $6,486,219 $1.70378

Waste Disposal

Spent Mercury Catalyst (lb.): 0 231 $0.65 $0 $43,941 $0.01154

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 641 $25.11 $0 $4,701,292 $1.23492

 Subtotal: $0 $4,745,232 $1.24646

By-Products

Sulfur (tons): 0 146 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $16,547,652 $46,580,031 $12.23551

Fuel Cost

Illinois Number 6 (ton): 0 5,844 $68.54 $0 $116,961,258 $30.72304

Total: $0 $116,961,258 $30.72304

Exhibit 3-107 Case B5B COE breakdown

Component Value, $/MWh Percentage

Capital 74.2 55%

Fixed 18.2 13%

Variable 12.2 9%

Fuel 30.7 23%

Total (Excluding T&S) 135.4 N/A

CO2 T&S 9.2 7%

Total (Including T&S) 144.7 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.4.12 Case B5B-Q - GEE Quench IGCC with CO2 Capture

Case B5B-Q is configured to produce electric power with CO2 capture. The plant configuration 

is the same as Case B5B, namely two gasifier trains, two state-of-the-art 2008 F-class turbines, 

two HRSGs, and one steam turbine.

The process description for Case B5B-Q is similar to Case B5B with the exception that the 

gasifier is operated in quench-only mode. A BFD and stream tables for Case B5B-Q are shown 

in Exhibit 3-108 and Exhibit 3-109, respectively. Rather than repeating the entire process 

description, only differences from Case B5B are reported here.

3.4.12.1 Gasification

The gasification process is the same as Case B5B with the exception that the syngas exiting the 

gasifier passes through a water quench where the temperature is reduced from 1,316°C (2,400°F) 

to 288°C (550°F). The total coal feed to the two gasifiers is 5,301 tonnes/day (5,844 tpd) 

(stream 6) and the ASU provides 4,343 tonnes/day (4,787 tpd) of 95 percent oxygen to the 

gasifier and Claus plant (streams 3 and 5).

3.4.12.2 Raw Gas Cooling/Particulate Removal

Particulate is largely removed in the quench tank and no additional heat recovery occurs prior to 

the syngas scrubber.

3.4.12.3 Syngas Scrubber/Sour Water Stripper

The outlet temperature from the syngas scrubber is 227°C (440°F) (stream 10).

3.4.12.4 Sour Gas Shift

The SGS process is the same as described for Case B5B with a 97 percent overall conversion of 

the CO to CO2. The warm syngas from the second stage of SGS (stream 12) is cooled to 244°C 

(471°F) by heating the syngas entering the first shift reactor. The syngas is then cooled to 193°C 

(380°F) by producing IP steam that is sent to the RH in the HRSG. The SGS catalyst also serves 

to hydrolyze COS thus eliminating the need for a separate COS hydrolysis reactor. Following 

the second SGS cooler the syngas is further cooled to 35°C (95°F) before entering the mercury 

removal beds.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-108 Case B5B-Q block flow diagram, GEE quench-only IGCC with CO2 capture

Source: NETL

GAS

TURBINE

COMBUSTOR

TURBINE COOLING AIR

QUENCH AND

SYNGAS

SCRUBBER

GAS COOLING

BFW HEATING

& KNOCKOUT

SHIFT

REACTORS

ELEVATED

PRESSURE

ASU

GEE GASIFIER

SECTION

SOUR

WATER

STRIPPER

MERCURY

REMOVAL

DUAL

STAGE

SELEXOL

UNIT

CLAUS

PLANT

HRSG

AMBIENT AIR

SYNGAS

EXPANDER

HYDROGENATION

REACTOR AND GAS

COOLER

CO2

COMPRESSION

1

5

9

10

11 12 13 14

17

19

20

21

18

8

2 3

4

22

23 24

AIR TO ASU

SLAG

SHIFT

STEAM

WATER RECYCLE

TO PROCESS

DEMAND

NOTE: WATER FROM TAIL

GAS COOLER MODELED, 

BUT NOT SHOWN

NITROGEN DILUENT

SYNGAS

CLEAN

GAS

CO2

STREAMS

CO2

PRODUCT

SULFUR

TAIL GAS

RECYCLE TO

SELEXOL

NOTE: TAIL GAS BOOST

COMPRESSOR MODELED, 

BUT NOT SHOWN

FLUE GAS

STACK GAS

VENT GAS

CLAUS

PLANT

OXIDANT

2X STATE-OF-THEART F-CLASS

GAS TURBINES

SYNGAS

H/P 

REHEAT

15

16

CLAUS

PLANT

OXIDANT

STEAM

TURBINE

25

SLURRY

MIXER 6

ASRECEIVED

COAL

7

SLURRY

WATER

GASIFIER

OXIDANT

Note: Block Flow Diagram is not intended to 

represent a complete material balance. Only 

major process streams and equipment are 

shown.

20

TAIL GAS

RECYCLE FROM

CLAUS PLANT
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-109 Case B5B-Q stream table, GEE quench-only IGCC with capture

1 2 3 4 5 6 7 8 9 10 11 12 13 14

V-L Mole Fraction

Ar 0.0092 0.0165 0.0318 0.0023 0.0318 0.0000 0.0000 0.0000 0.0086 0.0053 0.0000 0.0053 0.0071 0.0071

CH4 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0011 0.0007 0.0000 0.0007 0.0009 0.0009

CO 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3576 0.2197 0.0000 0.0060 0.0081 0.0081

CO2 0.0003 0.0054 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1380 0.0848 0.0000 0.2985 0.4017 0.4053

COS 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0002 0.0001 0.0000 0.0000 0.0000 0.0000

H2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.3406 0.2093 0.0000 0.4229 0.5690 0.5647

H2O 0.0099 0.1355 0.0000 0.0003 0.0000 0.0000 0.9997 0.0000 0.1369 0.4700 1.0000 0.2562 0.0012 0.0012

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0008 0.0001 0.0000 0.0001 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0073 0.0045 0.0000 0.0046 0.0061 0.0061

N2 0.7732 0.7077 0.0178 0.9920 0.0178 0.0000 0.0000 0.0000 0.0070 0.0043 0.0000 0.0043 0.0058 0.0065

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0003 0.0000 0.0019 0.0013 0.0000 0.0013 0.0000 0.0000

O2 0.2074 0.1349 0.9504 0.0054 0.9504 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 27,367 1,660 97 20,046 5,526 0 5,037 0 23,121 37,625 0 37,625 27,964 28,358

V-L Flowrate (kg/hr) 789,736 45,606 3,132 562,476 177,816 0 90,741 0 465,212 726,201 0 726,201 552,117 564,722

Solids Flowrate (kg/hr) 0 0 0 0 0 220,890 0 24,235 0 0 0 0 0 0

Temperature (°C) 15 18 32 93 32 15 146 1,316 1,316 227 288 249 35 35

Pressure (MPa, abs) 0.10 0.11 0.86 2.65 0.86 0.10 5.79 5.62 5.62 5.58 5.52 5.45 5.17 5.14

Steam Table Enthalpy (kJ/kg) A 30.23 35.62 26.67 92.50 26.67 --- 559.14 --- 2,635.52 1,479.99 2,918.18 1,017.28 36.94 36.25

AspenPlus Enthalpy (kJ/kg)B -97.58 -1,483.25 4.13 63.47 4.13 -2,116.95 -15,408.22 -727.24 -4,038.89 -8,545.15 -13,053.16 -8,965.22 -8,082.42 -8,084.87

Density (kg/m3) 1.2 1.5 11.0 24.4 11.0 --- 867.1 --- 8.5 25.9 25.6 24.5 41.0 41.2

V-L Molecular Weight 28.857 27.479 32.181 28.060 32.181 --- 18.015 --- 20.121 19.301 18.015 19.301 19.744 19.914

V-L Flowrate (lbmole/hr) 60,334 3,659 215 44,193 12,182 0 11,105 0 50,972 82,949 0 82,949 61,649 62,518

V-L Flowrate (lb/hr) 1,741,069 100,544 6,906 1,240,047 392,017 0 200,051 0 1,025,616 1,600,998 0 1,600,998 1,217,210 1,244,998

Solids Flowrate (lb/hr) 0 0 0 0 0 486,978 0 53,430 0 0 0 0 0 0

Temperature (°F) 59 65 90 199 90 59 295 2,400 2,400 440 550 481 95 95

Pressure (psia) 14.7 16.4 125.0 384.0 125.0 14.7 840.0 815.0 815.0 810.0 800.0 790.0 750.0 745.0

Steam Table Enthalpy (Btu/lb)A 13.0 15.3 11.5 39.8 11.5 --- 240.4 --- 1,133.1 636.3 1,254.6 437.4 15.9 15.6

AspenPlus Enthalpy (Btu/lb)B -42.0 -637.7 1.8 27.3 1.8 -910.1 -6,624.3 -312.7 -1,736.4 -3,673.8 -5,611.9 -3,854.3 -3,474.8 -3,475.9

Density (lb/ft3) 0.076 0.091 0.687 1.521 0.687 --- 54.131 --- 0.530 1.619 1.597 1.529 2.562 2.570

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

225

Exhibit 3-109 Case B5B-Q stream table, GEE quench-only IGCC with capture (continued)

15 16 17 18 19 20 21 22 23 24 25

V-L Mole Fraction

Ar 0.0115 0.0115 0.0115 0.0002 0.0018 0.0000 0.0103 0.0092 0.0091 0.0091 0.0000

CH4 0.0015 0.0015 0.0015 0.0000 0.0004 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

CO 0.0130 0.0130 0.0130 0.0002 0.0023 0.0000 0.0061 0.0000 0.0000 0.0000 0.0000

CO2 0.0501 0.0501 0.0501 0.9948 0.5218 0.0000 0.6606 0.0003 0.0083 0.0083 0.0000

COS 0.0000 0.0000 0.0000 0.0000 0.0002 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2 0.9133 0.9133 0.9133 0.0048 0.1029 0.0000 0.2596 0.0000 0.0000 0.0000 0.0000

H2O 0.0001 0.0001 0.0001 0.0000 0.0225 0.0000 0.0017 0.0099 0.1222 0.1222 1.0000

HCl 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

H2S 0.0000 0.0000 0.0000 0.0000 0.3472 0.0000 0.0043 0.0000 0.0000 0.0000 0.0000

N2 0.0105 0.0105 0.0105 0.0000 0.0008 0.0000 0.0574 0.7732 0.7541 0.7541 0.0000

NH3 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

O2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.2074 0.1064 0.1064 0.0000

SO2 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.0000 1.0000 1.0000 1.0000 1.0000 1.0000

V-L Flowrate (kgmole/hr) 17,424 17,424 17,424 10,415 496 0 394 110,253 139,653 139,653 20,013

V-L Flowrate (kg/hr) 90,438 90,438 90,438 456,223 17,655 0 12,604 3,181,557 3,834,472 3,834,472 360,534

Solids Flowrate (kg/hr) 0 0 0 0 0 5,523 0 0 0 0 0

Temperature (°C) 35 241 195 51 48 178 38 15 562 132 534

Pressure (MPa, abs) 5.14 5.10 3.17 15.27 0.16 0.12 5.51 0.10 0.10 0.10 12.51

Steam Table Enthalpy (kJ/kg) A 194.96 1,385.17 1,117.49 -162.29 74.70 --- 5.84 30.23 834.65 343.46 3,432.96

AspenPlus Enthalpy (kJ/kg)B -4,047.98 -2,857.76 -3,125.45 -9,120.15 -6,110.54 141.95 -8,192.39 -97.58 -588.07 -1,079.26 -12,537.35

Density (kg/m3) 10.2 6.1 4.2 641.8 2.2 5,280.6 77.3 1.2 0.4 0.9 36.7

V-L Molecular Weight 5.190 5.190 5.190 43.804 35.590 --- 31.966 28.857 27.457 27.457 18.015

V-L Flowrate (lbmole/hr) 38,414 38,414 38,414 22,961 1,094 0 869 243,066 307,882 307,882 44,120

V-L Flowrate (lb/hr) 199,383 199,383 199,383 1,005,800 38,923 0 27,788 7,014,133 8,453,564 8,453,564 794,842

Solids Flowrate (lb/hr) 0 0 0 0 0 12,177 0 0 0 0 0

Temperature (°F) 95 465 383 124 119 352 100 59 1,044 270 994

Pressure (psia) 745.0 740.0 460.0 2,214.7 23.7 17.3 799.5 14.7 15.2 15.2 1,814.7

Steam Table Enthalpy (Btu/lb)A 83.8 595.5 480.4 -69.8 32.1 --- 2.5 13.0 358.8 147.7 1,475.9

AspenPlus Enthalpy (Btu/lb)B -1,740.3 -1,228.6 -1,343.7 -3,921.0 -2,627.1 61.0 -3,522.1 -42.0 -252.8 -464.0 -5,390.1

Density (lb/ft3) 0.636 0.381 0.261 40.066 0.137 329.655 4.823 0.076 0.026 0.053 2.293

ASteam table reference conditions are 32.02°F & 0.089 psia

BAspen thermodynamic reference state is the component’s constituent elements in an ideal gas state at 25°C and 1 atm
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.4.12.5 Mercury Removal and Acid Gas Removal

Mercury removal and the AGR process are the same as in Case B5B.

The AGR process in Case B5B-Q is a two-stage Selexol process where H2S is removed in the 

first stage and CO2 in the second stage of absorption as previously described in Section 3.1.5. 

The process results in three product streams, the clean syngas, a CO2-rich stream and an acid gas 

feed to the Claus plant. The acid gas (stream 18) contains 35 percent H2S and 52 percent CO2

with the balance primarily H2.

3.4.12.6 CO2 Compression and Dehydration

The CO2 compression and dehydration scheme is the same as for Case B5B.

3.4.12.7 Claus Unit

The Claus plant is the same as Case B5B with the following exceptions:

• 5,523 kg/hr (12,177 lb/hr) of sulfur (stream 19) are produced

• The waste heat boiler generates 12,957 kg/hr (28,564 lb/hr) of 3.0 MPa (430 psia) steam

3.4.12.8 Power Block

Clean syngas from the AGR plant is heated to 241°C (465°F) first using hot water from the 

syngas scrubber followed by HP BFW before passing through an expansion turbine. The clean 

syngas (stream 16) is diluted with nitrogen (stream 4) and then enters the CT burner. There is no 

integration between the CT and the ASU in this case. The exhaust gas (stream 22) exits the CT 

at 562°C (1,044°F) and enters the HRSG where additional heat is recovered. The flue gas exits 

the HRSG at 132°C (270°F) (stream 23) and is discharged through the plant stack. The steam 

raised in the HRSG is used to power an advanced commercially available steam turbine using a 

nominal 12.4 MPa/538°C/538°C (1,800 psig/1,000°F/1,000°F) steam cycle.

3.4.12.9 Air Separation Unit

The same elevated pressure ASU is used in Case B5B-Q and produces 4,343 tonnes/day (4,787 

tpd) of 95 mol% oxygen and 14,595 tonnes/day (16,087 tpd) of nitrogen. There is no integration 

between the ASU and the CT in the CO2 capture cases.

3.4.13 Case B5B-Q - Performance Results

The plant produces a net output of 494 MW at a net plant efficiency of 29.7 percent (HHV 

basis). Overall performance for the entire plant is summarized in Exhibit 3-110 and 

Exhibit 3-111, which includes auxiliary power requirements. The ASU accounts for 60 percent 

of the auxiliary load between the main air compressor, nitrogen compressor, oxygen compressor,

and ASU auxiliaries. The two-stage Selexol process and CO2 compression account for an 

additional 26 percent of the auxiliary power load. The BFW pumps and cooling water system 

(CWPs and cooling tower fan) compose about 5 percent of the load, leaving 9 percent of the 

auxiliary load for all other systems.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

227

Exhibit 3-110 Case B5B-Q plant performance summary

Performance Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 214

Total Gross Power, MWe 684

Air Separation Unit Main Air Compressor, kWe 67,350

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,630

CO2 Compression, kWe 31,130

Acid Gas Removal, kWe 19,210

Balance of Plant, kWe 26,450

Total Auxiliaries, MWe 190

Net Power, MWe 494

HHV Net Plant Efficiency (%) 29.7%

HHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 12,138 (11,505)

HHV Cold Gas Efficiency, % 79.2%

HHV Combustion Turbine Efficiency, % 36.0%

LHV Net Plant Efficiency (%) 30.7%

LHV Net Plant Heat Rate, kJ/kWh (Btu/kWh) 11,708 (11,097)

LHV Cold Gas Efficiency, % 75.9%

LHV Combustion Turbine Efficiency, % 42.4%

Steam Turbine Cycle Efficiency, % 38.1%

Steam Turbine Heat Rate, kJ/kWh (Btu/kWh) 9,443 (8,950)

Condenser Duty, GJ/hr (MMBtu/hr) 1,452 (1,376)

As-Received Coal Feed, kg/hr (lb/hr) 220,890 (486,978)

HHV Thermal Input, kWt 1,664,962

LHV Thermal Input, kWt 1,605,876

Raw Water Withdrawal, (m3/min)/MWnet (gpm/MWnet) 0.047 (12.4)

Raw Water Consumption, (m3/min)/MWnet (gpm/MWnet) 0.038 (10.1)

O2:Coal 0.761
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

228

Exhibit 3-111 Case B5B-Q plant power summary

Power Summary

Combustion Turbine Power, MWe 464

Sweet Gas Expander Power, MWe 7

Steam Turbine Power, MWe 214

Total Gross Power, MWe 684

Auxiliary Load Summary

Coal Handling, kWe 470

Coal Milling, kWe 2,270

Sour Water Recycle Slurry Pump, kWe 200

Slag Handling, kWe 1,160

Air Separation Unit Auxiliaries, kWe 1,000

Air Separation Unit Main Air Compressor, kWe 67,350

Oxygen Compressor, kWe 10,640

Nitrogen Compressors, kWe 35,630

Feedwater Pumps, kWe 2,620

Quench Water Pump, kWe 1,270

Syngas Recycle Compressor, kWe 0

CO2 Compression, kWe 31,130

Scrubber Pumps, kWe 480

Acid Gas Removal, kWe 19,210

Combustion Turbine Auxiliaries, kWe 1,000

Steam Turbine Auxiliaries, kWe 100

Condensate Pumps, kWe 230

Circulating Water Pumps, kWe 4,830

Ground Water Pumps, kWe 560

Cooling Tower Fans, kWe 2,500

Claus Plant/TGTU Auxiliaries, kWe 250

Claus Plant TG Recycle Compressor, kWe 1,800

Miscellaneous Balance of PlantA,B, kWe 3,000

Transformer Losses, kWe 2,710

Total Auxiliaries, MWe 190

Net Power, MWe 494

AIncludes plant control systems, lighting, HVAC, and miscellaneous low voltage loads
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

229

3.4.13.1 Environmental Performance

The environmental targets for emissions of Hg, NOx, SO2, and PM were presented in 

Section 2.3. A summary of the plant air emissions for Case B5B-Q is presented in 

Exhibit 3-112. All HCl is assumed to be removed and is, therefore, not reported.

Exhibit 3-112 Case B5B-Q air emissions

kg/GJ (lb/MMBtu) Tonne/year (ton/year)A kg/MWh (lb/MWh)B

SO2 0.001 (0.002) 39 (43) 0.008 (0.018)

NOx 0.021 (0.049) 878 (968) 0.183 (0.404)

Particulates 0.003 (0.007) 128 (141) 0.027 (0.059)

Hg 1.55E-7 (3.61E-7) 0.007 (0.007) 1.36E-6 (3.00E-6)

CO2 8 (20) 358,178 (394,824) 75 (165)

CO2C - - 104 (228)

ACalculations based on an 80 percent capacity factor

BEmissions are based on gross power except where otherwise noted

CCO2 emissions based on net power instead of gross power

The low level of SO2 emissions is achieved by capturing the sulfur in the gas by the two-stage 

Selexol AGR process. As a result of achieving the 90 percent CO2 removal target, the sulfur 

compounds are removed to an extent that exceeds the environmental target in Section 2.3. The 

clean syngas exiting the AGR process has a sulfur concentration of approximately 5 ppmv. This 

results in a concentration in the flue gas of less than less than 1 ppmv. The H2S-rich 

regeneration gas from the AGR system is fed to a Claus plant, producing elemental sulfur. The 

Claus plant tail gas is hydrogenated to convert all sulfur species to H2S and then recycled back to 

the Selexol process, thereby eliminating the need for a tail gas treatment unit.

NOx emissions are limited by nitrogen dilution to 15 ppmvd (as NO2 @15 percent O2). 

Ammonia in the syngas is removed with process condensate prior to the low-temperature AGR 

process. This helps lower NOx levels as well.

Particulate discharge to the atmosphere is limited to extremely low values by the use of the 

syngas quench in addition to the syngas scrubber and the gas washing effect of the AGR 

absorber. The particulate emissions represent filterable particulate only.

Approximately 97 percent of the mercury is captured from the syngas by dual activated carbon 

beds.

Ninety two percent of the CO2 from the syngas is captured in the AGR system and compressed 

for sequestration. Because not all CO is converted to CO2 in the shift reactors, the overall carbon 

removal is 90.0 percent.

The carbon balance for the plant is shown in Exhibit 3-113. The carbon input to the plant 

consists of carbon in the air in addition to carbon in the coal. Carbon leaves the plant as 

unburned carbon in the slag and as CO2 in the stack gas, ASU vent gas, and the captured CO2

product. The carbon capture efficiency is defined as one minus the amount of carbon in the stack 

gas relative to the total carbon in less carbon contained in the slag, represented by the following 

fraction: 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

230

CCCCCCCCCC SS SSSS

(TT TT CCCCCCCCCC ) − (CCCCCCCCCC SS SS) = �1 − � 30,752

311,614 − 6,208� ∗� 100 = 90.0%

Exhibit 3-113 Case B5B-Q carbon balance

Carbon In Carbon Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 140,805 (310,423) Stack Gas 13,949 (30,752)

Air (CO2) 540 (1,191) CO2 Product 124,473 (274,417)

ASU Vent 107 (237)

Slag 2,816 (6,208)

Total 141,346 (311,614) Total 141,346 (311,614)

Exhibit 3-114 shows the sulfur balance for the plant. Sulfur input comes solely from the sulfur 

in the coal. Sulfur output includes the sulfur recovered in the Claus plant, sulfur co-sequestered 

with the CO2 product, and sulfur emitted in the stack gas. Sulfur in the slag is considered to be 

negligible.

Exhibit 3-114 Case B5B-Q sulfur balance

Sulfur In Sulfur Out

kg/hr (lb/hr) kg/hr (lb/hr)

Coal 5,536 (12,206) Stack Gas 3 (6)

CO2 Product 10 (23)

Elemental Sulfur 5,523 (12,177)

Total 5,536 (12,206) Total 5,536 (12,206)

Exhibit 3-115 shows the overall water balance for the plant. The exhibit is presented in an 

identical manner as for cases B1A-B5B.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

231

Exhibit 3-115 Case B5B-Q water balance

Water Use Water 

Demand

Internal 

Recycle

Raw Water 

Withdrawal

Process 

Water 

Discharge

Raw Water 

Consumption

m3/min 

(gpm)

m3/min 

(gpm)

m3/min 

(gpm) m3/min (gpm) m3/min (gpm)

Slag Handling 0.53 (139) 0.53 (139) – – –

Slurry Water 1.51 (400) 1.51 (400) – – –

Quench/Wash 6.66 (1,759) 1.86 (493) 4.79 (1,267) – 4.79 (1,267)

Humidifier – – – – –

SWS Blowdown – – – 0.04 (10.32) -0.04 (-10.32)

Condenser Makeup 0.15 (40) – 0.15 (40) – 0.15 (40)

 BFW Makeup 0.15 (40) – 0.15 (40) – 0.15 (40)

 Gasifier Steam – – – – –

 Shift Steam – – – – –

 CT Steam Dilution – – – – –

Cooling Tower 18.83 

(4,974) 0.54 (143) 18.29 (4,831) 4.23 (1,119) 14.05 (3,712)

 BFW Blowdown – 0.15 (40) -0.15 (-40) – -0.15 (-40)

 SWS Blowdown – 0.39 

(103.15)

-0.39 

(-103.15) – -0.39 (-103.15)

Total 27.68 

(7,311) 4.45 (1,174) 23.23 (6,137) 4.27 (1,129) 18.96 (5,008)

3.4.13.2 Heat and Mass Balance Diagrams

Heat and mass balance diagrams are shown for the following subsystems in Exhibit 3-116

through Exhibit 3-118:

• Coal gasification and ASU

• Syngas cleanup, sulfur recovery, and tail gas recycle

• Combined cycle power generation, steam, and FW

An overall plant energy balance is provided in tabular form in Exhibit 3-119. The power out is 

the combined CT, steam turbine, and expander power prior to generator losses. The power at the 

generator terminals (shown in Exhibit 3-118) is calculated by multiplying the power out by a 

combined generator efficiency of 98.5 percent.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

232

Exhibit 3-116 Case B5B-Q coal gasification and ASU heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B-Q

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B-Q

GEE GASIFIER

ASU AND GASIFICATION

DWG. NO.

BB-HMB-CS-B5B-Q-PG-1

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

1 OF 3

Ambient Air

Four Stage Air

Compressor

Elevated

Pressure

ASU

Four Stage N2

Compressor

Four Stage O2

Compressor

ASU 

Vent

1,741,069 W

59 T

15 P

13 H

392,017 W

90 T

125 P

11 H

392,017 W

241 T

940 P

41 H

To Claus Plant

6,906 W

90 T

125 P

11 H

100,544 W

65 T

16 P

15 H

1,083,235 W

90 T

56 P

14 H

156,812 W

50 T

182 P

3 H

5

1

3

2

Slurry Mix 

Tank

Milled Coal

Slag

486,978 W

59 T

15 P

200,051 W

295 T

840 P

240 H

53,430 W

2,400 T

815 P

677,219 W

385 T

384 P

87 H

687,029 W

160 T

840 P

1,739,515 W

100 T

190 P

18 H

6

677,219 W

199 T

384 P

40 H

N2 Boost

Compressor 562,828 W

199 T

384 P

40 H

562,828 W

385 T

469 P

87 H

GE Energy 

Gasifier

Syngas 

Scrubber

Slag Quench 

Section

Drag 

Conveyor

4

1,025,616 W

2,400 T

815 P

1,131 H

1,600,998 W

440 T

810 P

636 H

Syngas

Quench

1,905,244 W

550 T

815 P

761 H

8

9

10

879,627 W

371 T

1,200 P

329 H

From Sour

Water Stripper

To Fuel Gas 

Preheater

From Fuel Gas 

Preheater

809,952 W

440 T

810 P

475 H

809,952 W

150 T

1,205 P

118 H

To Sour

Water Stripper

69,400 W

329 T

115 P

277 H

7

N2 to GT Combustor

N2 to GT Combustor

Raw Fuel Gas

From HP 

Economizer 2

To HP Economizer 1

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Water

Steam

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Flue Gas/

Combustion

Products

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

Net Plant Heat Rate: 11,505 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

233

Exhibit 3-117 Case B5B-Q syngas cleanup heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B-Q

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B-Q

GEE GASIFIER

GAS CLEANUP SYSTEM

DWG. NO.

BB-HMB-CS-B5B-Q-PG-2

PLANT PERFORMANCE SUMMARY

LEGEND

PAGES

2 OF 3

Mercury 

Removal

Knock

Out

Drum

Sour

Drum

Claus Plant

Tail 

Gas

Furnace

Catalytic

Reactor

Beds

Sulfur

Knock Out

Syngas

Coolers

Sour

Stripper

1,600,998 W

440 T

810 P

636 H

1,244,998 W

95 T

745 P

16 H

38,923 W

119 T

24 P

32 H

199,383 W

383 T

460 P

480 H

12,177 W

36,695 W

450 T

12 P

467 H

3,043 W

246 T

65 P

500 H

19

13

20

36,695 W

550 T

11 P

429 H

1,217,210 W

95 T

750 P

16 H

8,907 W

114 T

11 P

40 H

27,788 W

100 T

800 P

3 H

15

199,383 W

95 T

745 P

84 H

18

Fuel Gas

Expander

16

199,383 W

465 T

740 P

596 H

High

Temperature

Shift #1

Low 

Temperature

Shift #2

12

1,600,998 W

450 T

805 P

621 H

1,600,998 W

782 T

800 P

606 H

1,600,998 W

425 T

800 P

440 H

1,600,998 W

481 T

790 P

437 H

1,600,998 W

471 T

785 P

432 H

Two-Stage

Selexol

Clean 

Gas

CO2

Acid 

Gas

Multistage 

Intercooled CO2

Compressor

Interstage Knockout

17

10

14

1,005,800 W

124 T

2,215 P

-70 H

Tail Gas Recycle

Compressor

Hydrogenation 

and Tail Gas 

Cooling

From IP 

BFW

To Reheater 

and Shift Steam

From IP BFW, 

LP BFW, and 

Tail Gas Cooling

1,149,078 W

From Syngas 

Scrubber

To Coal Slurry, Syngas Quench, and Slag Quench

To Water 

Treatment

Makeup Water

Raw Syngas

COS 

Hydrolysis 

Preheater

Reboiler

From Syngas 

Scrubber and HP 

Economizer 2

To Syngas 

Scrubber and HP 

Economizer 1

Fuel Gas 

Preheater Fuel Gas to CT

3

6,906 W

90 T

125 P

11 H

6,906 W

450 T

125 P

92 H

To 

Deaerator

From IP 

BFW

Claus 

Oxygen 

Preheater

From Gland Steam 

Condenser To Syngas 

Cooling

111 T

CO2 Product

To LP Turbine, Preheater

WGS/Gasifier Steam 

and Reheater 

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

Sour Water

Acid Gas

Tailgas

Carbon Dioxide

Sour Gas

Sulfur

Hydrogen

Water

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

Steam

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

Net Plant Heat Rate: 11,505 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

234

Exhibit 3-118 Case B5B-Q combined cycle power generation heat and mass balance schematic

Source: NETL

DOE/NETL

DUAL TRAIN IGCC PLANT

CASE B5B-Q

HEAT AND MATERIAL FLOW DIAGRAM

BITUMINOUS BASELINE STUDY

CASE B5B-Q

GEE GASIFIER

POWER BLOCK SYSTEM

DWG. NO.

BB-HMB-CS-B5B-Q-PG-3

PLANT PERFORMANCE SUMMARY

LEGEND

Air

Oxygen

Nitrogen

Coal/Char/

Slurry/Slag

Synthesis Gas

PAGES

3 OF 3

Sour Gas

Sour Water

Water

Steam

Flue Gas

HP

Turbine

IP

Turbine

Air Inlet 

Filter

Steam Seal 

Regulator

Blowdown 

Flash

Gland

Steam

Condenser

LP 

Turbine

Stack

Compressor Expander

Generator

Generator

Condensate

Pumpa

Steam Turbine

State-of-the-art 2008 

F-Class Turbine

7,014,133 W

59 T

15 P

13 H

1,523,777 W

101 T

1 P

69 H

8,453,564 W

270 T

15 P

148 H

199,383 W

383 T

460 P

480 H

794,842 W

994 T

1,815 P

1,468 H

6,775 W

298 T

65 P

1,171 H

1,491,802 W

441 T

65 P

1,245 H

1,523,777 W

103 T

120 P

71 H

1,400 W

615 T

65 P

1,331 H

1,400 W

212 T

15 P

180 H

21

24

16

23

Hot Well

Condenser

Make-up

19,815 W

59 T

15 P

27 H

9,026 W

661 T

501 P

1,327 H

9,761 W

615 T

65 P

1,331 H

798 W

994 T

1,815 P

1,468 H

1,337 W

505 T

65 P

1,277 H

Preheater Deaerator

Heater

HP 

Economizer 

1

LP 

Economizer

HP 

Economizer 

2

HP 

Evaporator

Superheater

/ Reheater

From Syngas 

Cooler

To ASU and Fuel 

Gas Preheater

Deaerator

HP Pump

IP Pump

To Claus

LP 

Evaporator

IP to Syngas and 

WGS Coolers 

From Claus, Process Extraction, 

and 250 PSIA Header

LP Extraction Spray

LP Blowdown

LP To Syngas 

Coolers

Cold Reheat

Hot Reheat

8,453,564 W

1,044 T

15 P

359 H 22

To WWT

Process 

Extraction

LP Pump

LP From 

Syngas Coolers

W Flowrate, lbm/hr 

T Temperature, °F

P Absolute Pressure, PSIA

H Enthalpy, Btu/lbm

MWe Power, Megawatts Electrical

235 T

274 T

1,525,679 W

274 T

45 P

242 H

813,794 W

279 T

2,251 P

247 H

7,628 W

274 T

79 P

242 H

5,928 W

274 T

79 P

242 H 342,287 W

274 T

79 P

242 H 40,181 W

276 T

615 P

244 H

367,487 W

351 T

2,251 P

319 H

305 T 585 T 636 T

18,961 W

585 T

2,001 P

585 H

550 T

766,193 W

661 T

501 P

1,327 H

367,487 W

585 T

2,001 P

585 H

332,253 W

298 T

65 P

266 H

170 T

252,538 W

298 T

65 P

1,171 H

356,041 W

298 T

65 P

1,171 H

296,945 W

276 T

820 P

244 H

1,000 W

994 T

1,815 P

1,468 H

1,000 W

212 T

15 P

180 H

39,537 W

500 T

250 P

1,255 H

IP Extraction Steam 

to 250 PSIA Header

LP Extraction Spray #1

Condensate to Tail 

Gas Cooling

677,219 W

385 T

469 P

87 H

Nitrogen Diluent

Fuel Gas

Ambient Air

IP From WGS and Syngas 

Coolers

994 T

298 T

From ASU and Fuel 

Gas Preheater

Nitrogen Diluent

562,828 W

385 T

384 P

87 H

Gross Plant Power: 684 MWe

Auxiliary Load: 190 MWe

Net Plant Power: 494 MWe

Net Plant Efficiency, HHV: 29.7%

Net Plant Heat Rate: 11,505 Btu/kWh

Notes:

1. Enthalpy reference point is natural state 

at 32 °F and 0.08865 psia
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

235

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Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

236

Exhibit 3-119 Case B5B-Q overall energy balance

HHV Sensible + 

Latent Power Total

Heat In (GJ/hr)

Coal 5,994 

(5,681)

5.0 (4.7) – 5,999 

(5,686)

Air – 120.0 (113.8) – 120.0 

(113.8)

Raw Water Makeup – 87.4 (82.8) – 87.4 (82.8)

Auxiliary Power – – 685 (650) 685 (650)

TOTAL 5,994 

(5,681)

212.4 (201.3) 685 (650) 6,892 

(6,532)

Heat Out (GJ/hr)

ASU Vent – 1.6 (1.5) – 1.6 (1.5)

Slag 92.3 (87.5) 37.8 (35.9) – 130.2 

(123.4)

Stack Gas – 1,317 (1,248) – 1,317 

(1,248)

Sulfur 51.2 (48.5) 0.6 (0.6) – 51.8 (49.1)

Motor Losses and Design 

Allowances

– – 57.1 (54.2) 57.1 (54.2)

Condenser – 1,452 (1,376) – 1,452 

(1,376)

Non-Condenser Cooling Tower 

Loads

– 830 (787) – 830 (787)

CO2 – -74.0 (-70.2) – -74.0 (-70.2)

Blowdown – 50.0 (47.4) – 50.0 (47.4)

CO2 Capture Losses – 176.2 (167.0) – 176.2 

(167.0)

Ambient LossesA – 163.1 (154.6) – 163.1 

(154.6)

Power – – 2,463 

(2,335)

2,463 

(2,335)

TOTAL 143.5 

(136.0)

3,955 (3,748) 2,520 

(2,389)

6,618 

(6,273)

Unaccounted EnergyB – 273 (259) – 273 (259)

AAmbient losses include all losses to the environment through radiation, convection, etc. Sources of these

losses include the combustor, reheater, superheater, and transformers.

BBy difference

3.4.14 Case B5B-Q - Major Equipment List

Major equipment items for the GEE quench-only gasifier with CO2 capture are shown in the 

following tables. The accounts used in the equipment list correspond to the account numbers 

used in the cost estimates in Section 3.4.15. In general, the design conditions include a 

10 percent contingency for flows and heat duties and a 21 percent contingency for heads on 

pumps and fans.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

237

Case B5B-Q – Account 1: Coal Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Bottom Trestle Dumper and 

Receiving Hoppers N/A 181 tonne (200 ton) 2 0

2 Feeder Belt 570 tonne/hr (630 tph) 2 0

3 Conveyor No. 1 Belt 1,130 tonne/hr (1,250 tph) 1 0

4 Conveyor No. 2 Belt 1,130 tonne/hr (1,250 tph) 1 0

5 Stacker/Reclaimer Traveling, linear 1,130 tonne/hr (1,250 tph) 1 0

6 Reclaim Hopper N/A 50 tonne (50 ton) 2 1

7 Feeder Vibratory 180 tonne/hr (200 tph) 2 1

8 Conveyor No. 3 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

9 Coal Surge Bin w/ Vent Filter Dual outlet 180 tonne (200 ton) 2 0

10 Crusher Impactor reduction 8 cm x 0 - 3 cm x 0

(3" x 0 - 1-1/4" x 0) 2 0

11 Conveyor No. 4 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

12 Conveyor No. 5 Belt w/ tripper 360 tonne/hr (400 tph) 1 0

13 Coal Silo w/ Vent Filter and 

Slide Gates Field erected 800 tonne (900 ton) 3 0

Case B5B-Q – Account 2: Coal Preparation and Feed

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Feeder Vibratory 80 tonne/h (90 tph) 3 0

2 Conveyor No. 6 Belt w/ tripper 240 tonne/h (270 tph) 1 0

3 Rod Mill Feed Hopper Dual Outlet 490 tonne (540 ton) 1 0

4 Weigh Feeder Belt 120 tonne/h (130 tph) 2 0

5 Rod Mill Rotary 120 tonne/h (130 tph) 2 0

6 Slurry Water Storage Tank with 

Agitator Field erected 299,880 liters (79,220 gal) 2 0

7 Slurry Water Pumps Centrifugal 830 lpm (220 gpm) 2 1

8 Trommel Screen Coarse 170 tonne/h (190 tph) 2 0

9 Rod Mill Discharge Tank with 

Agitator Field erected 392,290 liters (103,630 gal) 2 0

10 Rod Mill Product Pumps Centrifugal 3,300 lpm (900 gpm) 2 2

11 Slurry Storage Tank with 

Agitator Field erected 1,176,900 liters (310,900 gal) 2 0

12 Slurry Recycle Pumps Centrifugal 6,500 lpm (1,700 gpm) 2 2

13 Slurry Product Pumps Positive 

displacement 3,300 lpm (900 gpm) 2 2

Case B5B-Q – Account 3: Feedwater and Miscellaneous Systems and Equipment

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Demineralized Water 

Storage Tank

Vertical, cylindrical, 

outdoor 811,000 liters (214,000 gal) 2 0

2 Condensate Pumps Vertical canned 6,380 lpm @ 90 m H2O

(1,690 gpm @ 300 ft H2O) 2 1

3 Deaerator (integral w/ 

HRSG) Horizontal spray type 465,000 kg/hr (1,025,000 lb/hr) 2 0

4 Intermediate-Pressure 

Feedwater Pump

Horizontal centrifugal, 

single stage

6,600 lpm @ 30 m H2O

(1,740 gpm @ 90 ft H2O) 2 1

5 High-Pressure 

Feedwater Pump No. 1

Barrel type, multistage, centrifugal

HP water: 

3,520 lpm @ 1,800 m H2O

(930 gpm @ 6,100 ft H2O)

2 1

6 High-Pressure 

Feedwater Pump No. 2

Barrel type, multistage, centrifugal

IP water: 1,590 lpm @ 220 m 

H2O (420 gpm @ 730 ft H2O) 2 1
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

238

Equipment 

No. Description Type Design Condition Operating Qty. Spares

7 Auxiliary Boiler Shop fabricated, water 

tube

18,000 kg/hr, 2.8 MPa, 343°C

(40,000 lb/hr, 400 psig, 650°F) 1 0

8 Service Air 

Compressors Flooded Screw 28 m3/min @ 0.7 MPa(1,000 scfm @ 100 psig) 2 1

9 Instrument Air Dryers Duplex, regenerative 28 m3/min (1,000 scfm) 2 1

10 Closed Cycle Cooling 

Heat Exchangers Plate and frame 457 GJ/hr (433 MMBtu/hr) each 2 0

11 Closed Cycle Cooling 

Water Pumps Horizontal centrifugal 163,800 lpm @ 20 m H2O(43,300 gpm @ 70 ft H2O) 2 1

12 Engine-Driven Fire 

Pump

Vertical turbine, diesel 

engine

3,785 lpm @ 110 m H2O

(1,000 gpm @ 350 ft H2O) 1 1

13 Fire Service Booster 

Pump

Two-stage horizontal 

centrifugal

2,650 lpm @ 80 m H2O

(700 gpm @ 250 ft H2O) 1 1

14 Raw Water Pumps Stainless steel, single 

suction

6,030 lpm @ 20 m H2O

(1,590 gpm @ 60 ft H2O) 2 1

15 Ground Water Pumps Stainless steel, single 

suction

3,010 lpm @ 270 m H2O 

(800 gpm @ 880 ft H2O) 4 1

16 Filtered Water Pumps Stainless steel, single 

suction

4,170 lpm @ 50 m H2O

(1,100 gpm @ 160 ft H2O) 2 1

17 Filtered Water Tank Vertical, cylindrical 2,003,000 liter (529,000 gal) 2 0

18 Makeup Water 

Demineralizer

Anion, cation, and 

mixed bed 230 lpm (60 gpm) 2 0

19 Liquid Waste Treatment 

System N/A 10 years, 24-hour storm 1 0

Case B5B-Q – Account 4: Gasifier, ASU, and Accessories Including Low Temperature 

Heat Recovery and Fuel Gas Saturation

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Gasifier Pressurized slurry-feed, 

entrained bed

2,900 tonne/day, 5.6 MPa

(3,200 tpd, 815 psia) 2 0

2 Synthesis Gas Cooler

Vertical downflow 

radiant heat exchanger 

with outlet quench 

chamber

256,000 kg/hr (564,000 lb/hr) 2 0

3 Synthesis Gas 

Cyclone High efficiency 475,000 kg/hr (1,048,000 lb/hr) Design efficiency 90% 2 0

4 Raw Gas Coolers Shell and tube with 

condensate drain 399,000 kg/hr (881,000 lb/hr) 8 0

5 Raw Gas Knockout 

Drum

Vertical with mist 

eliminator

304,000 kg/hr, 35°C, 5.2 MPa

(671,000 lb/hr, 95°F, 755 psia) 2 0

6 Synthesis Gas 

Reheater Shell and Tube 50,000 kg/hr (110,000 lb/hr)

7 Flare Stack

Self-supporting, carbon 

steel, stainless steel 

top, pilot ignition

475,000 kg/hr (1,048,000 lb/hr) 

syngas

2 0

8 ASU Main Air 

Compressor Centrifugal, multi-stage 6,000 m3/min @ 1.3 MPa(210,000 scfm @ 190 psia) 2 0

9 Cold Box Vendor design 2,400 tonne/day (2,600 tpd) 

of 95% purity oxygen 2 0

10 Oxygen Compressor Centrifugal, multi-stage

1,000 m3/min (42,000 scfm)

Suction - 1.0 MPa (130 psia)

Discharge - 6.5 MPa (940 psia)

2 0

11 Primary Nitrogen 

Compressor Centrifugal, multi-stage

4,000 m3/min (134,000 scfm)

Suction - 0.4 MPa (60 psia)

Discharge - 2.7 MPa (390 psia)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

239

Equipment 

No. Description Type Design Condition Operating Qty. Spares

12 Secondary Nitrogen 

Compressor

Centrifugal, singlestage

550 m3/min (19,000 scfm)

Suction - 1.3 MPa (180 psia)

Discharge - 2.7 MPa (390 psia)

2 0

13

Syngas Dilution 

Nitrogen Boost 

Compressor

Centrifugal, singlestage

2,000 m3/min (70,000 scfm)

Suction - 2.6 MPa (380 psia)

Discharge - 3.2 MPa (470 psia)

2 0

Case B5B-Q – Account 5: Syngas Cleanup

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Mercury Adsorber 1 Sulfated carbon bed 304,000 kg/hr (669,000 lb/hr),

35°C (95°F), 5.2 MPa (750 psia) 2 0

2 Mercury Adsorber 2 Sulfated carbon bed 304,000 kg/hr (669,000 lb/hr),

35°C (95°F), 5.2 MPa (750 psia) 2 0

3 Sulfur Plant Claus type 146 tonne/day (161 tpd) 1 0

4 Water Gas Shift 

Reactors Fixed bed, catalytic 200,000 kg/hr (440,000 lb/hr),232°C (450°F), 5.5 MPa (800 psia) 4 0

5

Shift Reactor Heat 

Recovery 

Exchangers

Shell and Tube

Exchanger 1: 154 GJ/hr (146 

MMBtu/hr) 

Exchanger 2: 4 GJ/hr (4 MMBtu/hr) 

4 0

6 Acid Gas Removal 

Plant Two-stage Selexol 311,000 kg/hr (685,000 lb/hr),35°C (95°F), 5.1 MPa (745 psia) 2 0

7 Hydrogenation 

Reactor Fixed bed, catalytic

18,000 kg/hr (40,000 lb/hr),

232°C (450°F), 0.1 MPa (12.3 

psia)

1 0

8 Tail Gas Recycle 

Compressor Centrifugal 14,000 kg/hr (31,000 lb/hr) each 1 0

9 CO2 Compressor

Integrally geared, 

multi-stage 

centrifugal

1,100 m3/min @ 15.3 MPa (39,900 

scfm @ 2,215 psia) 4 0

Case B5B-Q – Account 6: Combustion Turbine and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Combustion Turbine State-of-the-art 

2008 F-class 230 MW 2 0

2 Combustion Turbine

Generator TEWAC 260 MVA @ 0.9 p.f., 24 kV, 60 Hz, 3-phase 2 0

3 Syngas Expansion 

Turbine/Generator Turbo Expander

49,700 kg/h (109,700 lb/h)

5.1 MPa (740 psia) Inlet

3.2 MPa (460 psia) Outlet

2 0

Case B5B-Q – Account 7: HRSG, Ducting, and Stack

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Stack CS plate, type 

409SS liner

76 m (250 ft) high x

8.5 m (28 ft) diameter 1 0

2 Heat Recovery 

Steam Generator

Drum, multipressure with 

economizer section 

and integral 

deaerator

Main steam - 198,294 kg/hr, 

12.4 MPa/534°C 

(437,163 lb/hr, 1,800 psig/994°F)

2 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

240

Case B5B-Q – Account 8: Steam Turbine Generator and Auxiliaries

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Steam 

Turbine

Commercially available 

advanced steam turbine

225 MW

12.4 MPa/534°C/534°C (1,800 psig/ 

994°F/994°F)

1 0

2

Steam 

Turbine 

Generator

Hydrogen cooled, static 

excitation

250 MVA @ 0.9 p.f., 24 kV, 60 Hz, 

3-phase 1 0

3 Surface 

Condenser

Single pass, divided 

waterbox including 

vacuum pumps

1,600GJ/hr (1,510 MMBtu/hr), 

Inlet water temperature 16°C 

(60°F), 

Water temperature rise 11°C (20°F)

1 0

4 Steam 

Bypass One per HRSG 50% steam flow @ design steam conditions 2 0

Case B5B-Q – Account 9: Cooling Water System

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Circulating 

Water Pumps Vertical, wet pit 485,000 lpm @ 30 m(128,000 gpm @ 100 ft) 2 1

2 Cooling Tower

Evaporative, 

mechanical draft, 

multi-cell

11°C (51.5°F) wet bulb /

16°C (60°F) CWT /

27°C (80°F) HWT /

2,700 GJ/hr (2,560 MMBtu/hr) heat duty

1 0

Case B5B-Q – Account 10: Slag Recovery and Handling

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 Slag Quench Tank Water bath 254,000 liters (67,000 gal) 2 0

2 Slag Crusher Roll 13 tonne/hr (15 tph) 2 0

3 Slag Depressurizer Lock Hopper 13 tonne/hr (15 tph) 2 0

4 Slag Receiving Tank Horizontal, weir 153,000 liters (40,000 gal) 2 0

5 Black Water Overflow Tank Shop fabricated 69,000 liters (18,000 gal) 2 0

6 Slag Conveyor Drag chain 13 tonne/hr (15 tph) 2 0

7 Slag Separation Screen Vibrating 13 tonne/hr (15 tph) 2 0

8 Coarse Slag Conveyor Belt/bucket 13 tonne/hr (15 tph) 2 0

9 Fine Ash Settling Tank Vertical, gravity 217,000 liters (57,000 gal) 2 0

10 Fine Ash Recycle Pumps Horizontal centrifugal 60 lpm @ 14 m H2O

(10 gpm @ 46 ft H2O) 2 2

11 Grey Water Storage Tank Field erected 69,000 liters (18,000 gal) 2 0

12 Grey Water Pumps Centrifugal 250 lpm @ 560 m H2O

(60 gpm @ 1,850 ft H2O) 2 2

13 Slag Storage Bin Vertical, field erected 1,000 tonne (1,100 tons) 2 0

14 Unloading Equipment Telescoping chute 110 tonne/hr (120 tph) 1 0
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

241

Case B5B-Q – Account 11: Accessory Electric Plant

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 CTG Transformer Oil-filled 24 kV/345 kV, 260 

MVA, 3-ph, 60 Hz 2 0

2 STG Transformer Oil-filled 24 kV/345 kV, 200 

MVA, 3-ph, 60 Hz 1 0

3 High Voltage Auxiliary 

Transformer Oil-filled 345 kV/13.8 kV, 80 MVA, 3-ph, 60 Hz 2 0

4 Medium Voltage Transformer Oil-filled 24 kV/4.16 kV, 48 

MVA, 3-ph, 60 Hz 1 1

5 Low Voltage Transformer Dry ventilated 4.16 kV/480 V, 7 

MVA, 3-ph, 60 Hz 1 1

6 CTG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 2 0

7 STG Isolated Phase Bus Duct 

and Tap Bus

Aluminum, selfcooled 24 kV, 3-ph, 60 Hz 1 0

8 Medium Voltage Switchgear Metal clad 4.16 kV, 3-ph, 60 Hz 1 1

9 Low Voltage Switchgear Metal enclosed 480 V, 3-ph, 60 Hz 1 1

10 Emergency Diesel Generator Sized for emergency 

shutdown

750 kW, 480 V, 3-

ph, 60 Hz 1 0

Case B5B-Q – Account 12: Instrumentation and Control

Equipment 

No. Description Type Design Condition Operating Qty. Spares

1 DCS - Main 

Control

Monitor/keyboard; Operator 

printer (laser color); Engineering 

printer (laser B&W)

Operator stations/printers 

and engineering 

stations/printers

1 0

2 DCS - Data 

Highway Fiber optic Fully redundant, 25% spare 1 0

3.4.15 Case B5B-Q - Cost Estimating

The cost estimating methodology was described previously in Section 2.6. Exhibit 3-120 shows 

a detailed breakdown of the capital costs; Exhibit 3-121 shows the owner’s costs, TOC, and 

TASC; Exhibit 3-122 shows the initial and annual O&M costs; and Exhibit 3-123 shows the 

COE breakdown. 

The estimated TPC of the GEE gasifier with CO2 capture in quench-only configuration is 

$3,405/kW. Process contingency represents 4.0 percent of the TOC and project contingency 

represents 13.7 percent. The COE, including CO2 T&S costs of $10.2/MWh, is $148.9/MWh. 

For comparison, the TPC and COE for Case B5B, GEE in radiant-only configuration with CO2

capture, are $3,387/kW and $144.7/MWh.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

242

Exhibit 3-120 Case B5B-Q total plant cost details

Case: B5B-Q – GEE Quench IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

1 Coal & Sorbent Handling

1.1 Coal Receive & Unload $4,552 $0 $2,194 $0 $6,746 $675 $0 $1,484 $8,905 $18

1.2 Coal Stackout & Reclaim $5,882 $0 $1,406 $0 $7,289 $729 $0 $1,604 $9,621 $19

1.3 Coal Conveyors & Yd Crush $5,469 $0 $1,392 $0 $6,861 $686 $0 $1,509 $9,056 $18

1.4 Other Coal Handling $1,431 $0 $322 $0 $1,753 $175 $0 $386 $2,314 $5

1.9 Coal & Sorbent Hnd. Foundations $0 $3,040 $7,944 $0 $10,984 $1,098 $0 $2,416 $14,499 $29

Subtotal $17,334 $3,040 $13,258 $0 $33,632 $3,363 $0 $7,399 $44,394 $90

2 Coal & Sorbent Prep & Feed

2.1 Coal Crushing & Drying w/2.3 $0 w/2.3 $0 $0 $0 $0 $0 $0 $0

2.2 Prepared Coal Storage & Feed $1,944 $467 $301 $0 $2,712 $271 $0 $597 $3,580 $7

2.3 Slurry Prep & Feed $23,378 $0 $14,694 $0 $38,072 $3,807 $1,904 $8,757 $52,539 $106

2.4 Misc. Coal Prep & Feed $1,069 $781 $2,301 $0 $4,151 $415 $0 $913 $5,479 $11

2.9 Coal & Sorbent Feed Foundation $0 $3,922 $3,365 $0 $7,287 $729 $0 $1,603 $9,618 $19

Subtotal $26,391 $5,170 $20,660 $0 $52,221 $5,222 $1,904 $11,869 $71,217 $144

3 Feedwater & Miscellaneous BOP Systems

3.1 Feedwater System $2,281 $3,936 $2,064 $0 $8,280 $828 $0 $1,822 $10,930 $22

3.2 Water Makeup & Pretreating $908 $94 $499 $0 $1,501 $150 $0 $495 $2,146 $4

3.3 Other Feedwater Subsystems $1,282 $424 $379 $0 $2,085 $208 $0 $459 $2,752 $6

3.4 Service Water Systems $531 $1,059 $3,650 $0 $5,240 $524 $0 $1,729 $7,493 $15

3.5 Other Boiler Plant Systems $2,862 $1,069 $2,632 $0 $6,563 $656 $0 $1,444 $8,663 $18

3.6 FO Supply Sys & Nat Gas $17,720 $682 $631 $0 $19,033 $1,903 $0 $4,187 $25,124 $51

3.7 Waste Treatment Equipment $1,229 $0 $761 $0 $1,990 $199 $0 $657 $2,845 $6

3.8 Misc. Power Plant Equipment $1,273 $170 $661 $0 $2,104 $210 $0 $694 $3,009 $6

Subtotal $28,086 $7,433 $11,277 $0 $46,795 $4,680 $0 $11,487 $62,962 $128

4 Gasifier & Accessories

4.1 Quench Gasifier System $79,525 $0 $68,344 $0 $147,869 $14,787 $19,355 $28,338 $210,349 $426

4.3 ASU & Oxidant Compression $231,253 $0 w/equip. $0 $231,253 $23,125 $0 $25,438 $279,816 $567

4.4 Scrubber & LT Heat Recovery $8,555 $0 $0 $0 $8,555 $855 $0 $1,882 $11,292 $23

4.5 Black Water & Sour Gas Section w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

4.8 Major Component Rigging w/4.1&4.2 $0 w/4.1&4.2 $0 $0 $0 $0 $0 $0 $0

4.9 Gasification Foundations $0 $3,060 $2,670 $0 $5,730 $573 $0 $1,576 $7,879 $16

Subtotal $319,333 $3,060 $71,014 $0 $393,407 $39,341 $19,355 $57,233 $509,336 $1,031

5A Gas Cleanup & Piping

5A.1 Double Stage Selexol $160,990 $0 w/equip. $0 $160,990 $16,099 $32,198 $41,857 $251,145 $509

5A.2 Elemental Sulfur Plant $12,451 $2,427 $15,954 $0 $30,831 $3,083 $0 $6,783 $40,697 $82

5A.3 Mercury Removal $1,967 $0 $1,487 $0 $3,454 $345 $173 $794 $4,767 $10

5A.4 Shift Reactors $12,108 $0 $4,841 $0 $16,949 $1,695 $0 $3,729 $22,373 $45

5A.7 Fuel Gas Piping $0 $810 $530 $0 $1,340 $134 $0 $295 $1,769 $4

5A.9 HGCU Foundations $0 $733 $494 $0 $1,227 $123 $0 $405 $1,755 $4

Subtotal $187,516 $3,970 $23,306 $0 $214,792 $21,479 $32,371 $53,863 $322,505 $653
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

243

Case: B5B-Q – GEE Quench IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

5B CO2 Compression

5B.2 CO2 Compression & Drying $40,213 $6,032 $17,419 $0 $63,663 $6,366 $0 $14,006 $84,035 $170

Subtotal $40,213 $6,032 $17,419 $0 $63,663 $6,366 $0 $14,006 $84,035 $170

6 Combustion Turbine & Accessories

6.1 Combustion Turbine Generator $111,210 $0 $7,881 $0 $119,091 $11,909 $11,909 $14,291 $157,201 $318

6.2 Syngas Expander $6,686 $0 $918 $0 $7,604 $760 $0 $1,255 $9,619 $19

6.9 Combustion Turbine Foundations $0 $1,016 $1,175 $0 $2,191 $219 $0 $723 $3,133 $6

Subtotal $117,896 $1,016 $9,974 $0 $128,886 $12,889 $11,909 $16,269 $169,953 $344

7 HRSG, Ducting, & Stack

7.1 Heat Recovery Steam Generator $29,570 $0 $5,726 $0 $35,296 $3,530 $0 $3,883 $42,708 $86

7.3 Ductwork $0 $2,109 $1,478 $0 $3,587 $359 $0 $789 $4,734 $10

7.4 Stack $4,069 $0 $1,518 $0 $5,587 $559 $0 $615 $6,761 $14

7.9 HRSG, Duct & Stack Foundations $0 $775 $778 $0 $1,552 $155 $0 $512 $2,220 $4

Subtotal $33,639 $2,883 $9,499 $0 $46,022 $4,602 $0 $5,798 $56,423 $114

8 Steam Turbine Generator

8.1 Steam TG & Accessories $35,245 $0 $4,866 $0 $40,111 $4,011 $0 $4,412 $48,535 $98

8.2 Turbine Plant Auxiliaries $206 $0 $470 $0 $676 $68 $0 $74 $818 $2

8.3 Condenser & Auxiliaries $3,200 $0 $1,812 $0 $5,012 $501 $0 $551 $6,064 $12

8.4 Steam Piping $10,865 $0 $4,712 $0 $15,577 $1,558 $0 $4,284 $21,418 $43

8.9 TG Foundations $0 $951 $1,680 $0 $2,630 $263 $0 $868 $3,761 $8

Subtotal $49,516 $951 $13,540 $0 $64,006 $6,401 $0 $10,190 $80,597 $163

9 Cooling Water System

9.1 Cooling Towers $4,640 $0 $1,400 $0 $6,040 $604 $0 $997 $7,641 $15

9.2 Circulating Water Pumps $2,236 $0 $170 $0 $2,405 $241 $0 $397 $3,043 $6

9.3 Circ. Water System Auxiliaries $194 $0 $27 $0 $221 $22 $0 $36 $280 $1

9.4 Circ. Water Piping $0 $8,587 $2,080 $0 $10,667 $1,067 $0 $2,347 $14,081 $29

9.5 Make-up Water System $499 $0 $686 $0 $1,185 $118 $0 $261 $1,564 $3

9.6 Component Cooling Water Sys $982 $1,174 $806 $0 $2,962 $296 $0 $652 $3,910 $8

9.9 Circ. Water System Foundations $0 $2,811 $4,995 $0 $7,806 $781 $0 $2,576 $11,162 $23

Subtotal $8,550 $12,572 $10,164 $0 $31,286 $3,129 $0 $7,265 $41,680 $84

10 Ash & Spent Sorbent Handling Systems

10.1 Slag Dewatering & Cooling $14,630 $8,067 $16,277 $0 $38,974 $3,897 $0 $4,287 $47,158 $96

10.2 Gasifier Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.3 Cleanup Ash Depressurization w/10.1 w/10.1 w/10.1 $0 $0 $0 $0 $0 $0 $0

10.6 Ash Storage Silos $710 $0 $767 $0 $1,476 $148 $0 $244 $1,868 $4

10.7 Ash Transport & Feed Equipment $977 $0 $228 $0 $1,205 $120 $0 $199 $1,524 $3

10.8 Misc. Ash Handling Equipment $1,470 $1,801 $534 $0 $3,805 $381 $0 $628 $4,814 $10

10.9 Ash/Spent Sorbent Foundation $0 $60 $78 $0 $138 $14 $0 $46 $197 $0

Subtotal $17,786 $9,928 $17,884 $0 $45,598 $4,560 $0 $5,403 $55,561 $113

11 Accessory Electric Plant

11.1 Generator Equipment $1,106 $0 $1,077 $0 $2,183 $218 $0 $240 $2,641 $5

11.2 Station Service Equipment $5,479 $0 $504 $0 $5,983 $598 $0 $658 $7,240 $15
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

244

Case: B5B-Q – GEE Quench IGCC w/ CO2 Estimate Type: Conceptual

Plant Size (MW,net): 494 Cost Base: Jun 2011

Item Description Equipment Material Labor Bare Erected Eng'g CM Contingencies Total Plant Cost

No. Cost Cost Direct Indirect Cost H.O.& Fee Process Project $/1,000 $/kW

11.3 Switchgear & Motor Control $10,113 $0 $1,880 $0 $11,993 $1,199 $0 $1,979 $15,171 $31

11.4 Conduit & Cable Tray $0 $5,139 $15,840 $0 $20,978 $2,098 $0 $5,769 $28,845 $58

11.5 Wire & Cable $0 $9,907 $6,028 $0 $15,935 $1,594 $0 $4,382 $21,911 $44

11.6 Protective Equipment $0 $806 $2,995 $0 $3,801 $380 $0 $627 $4,808 $10

11.7 Standby Equipment $265 $0 $264 $0 $529 $53 $0 $87 $669 $1

11.8 Main Power Transformers $18,924 $0 $164 $0 $19,088 $1,909 $0 $3,149 $24,146 $49

11.9 Electrical Foundations $0 $172 $468 $0 $639 $64 $0 $211 $914 $2

Subtotal $35,887 $16,024 $29,218 $0 $81,130 $8,113 $0 $17,103 $106,346 $215

12 Instrumentation & Control

12.1 IGCC Control Equipment w/4.1 $0 w/4.1 $0 $0 $0 $0 $0 $0 $0

12.2 Combustion Turbine Control w/6.1 $0 w/6.1 $0 $0 $0 $0 $0 $0 $0

12.3 Steam Turbine Control w/8.1 $0 w/8.1 $0 $0 $0 $0 $0 $0 $0

12.4 Other Major Component Control $1,271 $0 $866 $0 $2,138 $214 $107 $369 $2,827 $6

12.5 Signal Processing Equipment w/12.7 $0 w/12.7 $0 $0 $0 $0 $0 $0 $0

12.6 Control Boards, Panels & Racks $292 $0 $191 $0 $483 $48 $24 $111 $667 $1

12.7 Computer & Accessories $6,782 $0 $222 $0 $7,004 $700 $350 $805 $8,860 $18

12.8 Instrument Wiring & Tubing $0 $2,611 $4,942 $0 $7,553 $755 $378 $2,171 $10,857 $22

12.9 Other I & C Equipment $4,534 $0 $2,246 $0 $6,780 $678 $339 $1,170 $8,966 $18

Subtotal $12,879 $2,611 $8,467 $0 $23,957 $2,396 $1,198 $4,626 $32,177 $65

13 Improvements to Site

13.1 Site Preparation $0 $119 $2,706 $0 $2,826 $283 $0 $932 $4,041 $8

13.2 Site Improvements $0 $2,117 $2,993 $0 $5,110 $511 $0 $1,686 $7,307 $15

13.3 Site Facilities $3,794 $0 $4,259 $0 $8,053 $805 $0 $2,657 $11,516 $23

Subtotal $3,794 $2,236 $9,958 $0 $15,988 $1,599 $0 $5,276 $22,864 $46

14 Buildings & Structures

14.1 Combustion Turbine Area $0 $317 $179 $0 $496 $50 $0 $109 $655 $1

14.2 Steam Turbine Building $0 $2,511 $3,575 $0 $6,086 $609 $0 $1,004 $7,698 $16

14.3 Administration Building $0 $1,033 $749 $0 $1,781 $178 $0 $294 $2,253 $5

14.4 Circulation Water Pumphouse $0 $194 $103 $0 $296 $30 $0 $49 $375 $1

14.5 Water Treatment Buildings $0 $746 $728 $0 $1,474 $147 $0 $243 $1,865 $4

14.6 Machine Shop $0 $529 $361 $0 $890 $89 $0 $147 $1,126 $2

14.7 Warehouse $0 $853 $551 $0 $1,404 $140 $0 $232 $1,776 $4

14.8 Other Buildings & Structures $0 $511 $398 $0 $909 $91 $0 $200 $1,200 $2

14.9 Waste Treating Building & Str. $0 $1,143 $2,182 $0 $3,325 $332 $0 $731 $4,389 $9

Subtotal $0 $7,836 $8,825 $0 $16,661 $1,666 $0 $3,009 $21,337 $43

Total $898,821 $84,762 $274,464 $0 $1,258,047 $125,805 $66,737 $230,797 $1,681,386 $3,405
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-121 Case B5B-Q owner’s costs

Description $/1,000 $/kW

Pre-Production Costs

6 Months All Labor $14,334 $29

1 Month Maintenance Materials $3,191 $6

1 Month Non-fuel Consumables $700 $1

1 Month Waste Disposal $494 $1

25% of 1 Months Fuel Cost at 100% CF $3,046 $6

2% of TPC $33,628 $68

Total $55,393 $112

Inventory Capital

60-day supply of fuel and consumables at 100% CF $25,317 $51

0.5% of TPC (spare parts) $8,407 $17

Total $33,724 $68

Other Costs

Initial Cost for Catalyst and Chemicals $16,691 $34

Land $900 $2

Other Owner's Costs $252,208 $511

Financing Costs $45,397 $92

Total Overnight Costs (TOC) $2,085,698 $4,224

TASC Multiplier (IOU, high-risk, 35 year) 1.140

Total As-Spent Cost (TASC) $2,377,696 $4,815
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Exhibit 3-122 Case B5B-Q initial and annual operating and maintenance costs

Case: B5B-Q – GEE Quench IGCC w/ CO2 Cost Base: Jun 2011

Plant Size (MW,net): 494 Heat Rate-net (Btu/kWh): 11,505 Capacity Factor (%): 80

Operating & Maintenance Labor

Operating Labor Operating Labor Requirements per Shift

 Operating Labor Rate (base): 39.70 $/hour Skilled Operator: 2.0 

 Operating Labor Burden: 30.00 % of base Operator: 10.0 

 Labor O-H Charge Rate: 25.00 % of labor Foreman: 1.0 

Lab Tech's, etc.: 3.0 

Total: 16.0 

Fixed Operating Costs

Annual Cost

($) ($/kW-net)

Annual Operating Labor: $7,233,658 $14.649

Maintenance Labor: $15,699,956 $31.795

Administrative & Support Labor: $5,733,403 $11.611

Property Taxes and Insurance: $33,627,713 $68.101

Total: $62,294,730 $126.156

Variable Operating Costs

($) ($/MWh-net)

Maintenance Material: $30,633,669 $8.85243

Consumables

Consumption Cost ($)

Initial Fill Per Day Per Unit Initial Fill

Water (/1000 gallons): 0 4,419 $1.67 $0 $2,159,895 $0.62416

Makeup and Waste Water 

Treatment Chemicals (lbs):

0 26,325 $0.27 $0 $2,058,884 $0.59497

Carbon (Mercury Removal) (lb): 135,505 232 $5.50 $745,276 $372,638 $0.10768

Shift Catalyst (ft3): 6,443 4.41 $771.99 $4,973,767 $994,753 $0.28746

Selexol Solution (gal): 298,221 95 $36.79 $10,971,928 $1,019,146 $0.29451

Claus Catalyst (ft3): w/equip 2.01 $203.15 $0 $119,480 $0.03453

Subtotal: $16,690,971 $6,724,798 $1.94331

Waste Disposal

Spent Mercury Catalyst (lb.): 0 232 $0.65 $0 $44,045 $0.01273

Flyash (ton): 0 0 $0.00 $0 $0 $0.00000

Slag (ton): 0 641 $25.11 $0 $4,701,028 $1.35849

 Subtotal: $0 $4,745,073 $1.37122

By-Products

Sulfur (tons): 0 146 $0.00 $0 $0 $0.00000

Subtotal: $0 $0 $0.00000

Variable Operating Costs Total: $16,690,971 $42,103,540 $12.16696

Fuel Cost

Illinois Number 6 (ton): 0 5,844 $68.54 $0 $116,954,695 $33.79724

Total: $0 $116,954,695 $33.79724

Exhibit 3-123 Case B5B-Q COE breakdown

Component Value, $/MWh Percentage

Capital 74.7 54%

Fixed 18.0 13%

Variable 12.2 9%

Fuel 33.8 24%

Total (Excluding T&S) 138.7 N/A

CO2 T&S 10.2 7%

Total (Including T&S) 148.9 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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3.5 IGCC Case Summary

The performance results of the seven IGCC plant configurations modeled in this report are 

summarized in Exhibit 3-124.

Exhibit 3-124 Estimated performance and cost results for all cases

Integrated Gasification Combined CycleA

Shell E-GasTM FSQ GEE R+Q

Case B1A B1B B4A B4B B5A B5B B5B-Q

PERFORMANCE

Nominal CO2 Capture 0% 90% 0% 90% 0% 90% 90%

Capacity Factor 80% 80% 80% 80% 80% 80% 80%

Gross Power Output (MWe) 737 673 738 704 748 734 684

Auxiliary Power Requirement (MWe) 108 177 113 190 126 191 190

Net Power Output (MWe) 629 497 625 513 622 543 494

Coal Flow rate (lb/hr) 436,646 465,264 459,956 484,212 466,898 487,005 486,978

Natural Gas Flow rate (lb/hr) N/A N/A N/A N/A N/A N/A N/A

HHV Thermal Input (kWt) 1,492,878 1,590,722 1,572,575 1,655,503 1,596,309 1,665,056 1,664,962

Net Plant HHV Efficiency (%) 42.1% 31.2% 39.7% 31.0% 39.0% 32.6% 29.7%

Net Plant HHV Heat Rate (Btu/kWh) 8,100 10,927 8,585 11,002 8,758 10,459 11,505

Raw Water Withdrawal, gpm 4,150 5,652 4,382 5,757 4,755 5,834 6,137

Process Water Discharge, gpm 788 1,021 905 1,095 984 1,080 1,129

Raw Water Consumption, gpm 3,362 4,631 3,477 4,662 3,771 4,754 5,008

CO2 Capture Rate (%) 0 90 0 90 0 90 90

CO2 Emissions (lb/MMBtu) 197 20 199 20 197 20 20

CO2 Emissions (lb/MWh-gross) 1,361 161 1,448 158 1,434 152 165

CO2 Emissions (lb/MWh-net) 1,595 218 1,711 217 1,724 206 228

SO2 Emissions (lb/MMBtu) 0.004 0.002 0.012 0.002 0.001 0.002 0.002

SO2 Emissions (lb/MWh-gross) 0.029 0.017 0.085 0.017 0.009 0.017 0.018

NOx Emissions (lb/MMBtu) 0.059 0.049 0.060 0.049 0.059 0.049 0.049

NOx Emissions (lb/MWh-gross) 0.409 0.396 0.434 0.396 0.430 0.376 0.404

PM Emissions (lb/MMBtu) 0.007 0.007 0.007 0.007 0.007 0.007 0.007

PM Emissions (lb/MWh-gross) 0.049 0.057 0.052 0.057 0.052 0.055 0.059

Hg Emissions (lb/TBtu) 0.434 0.372 0.413 0.374 0.412 0.388 0.361

Hg Emissions (lb/MWh-gross) 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06 3.00E-06

COST

Total Plant Cost (2011$/kW) 2,725 3,981 2,372 3,540 2,449 3,387 3,405

Bare Erected Cost 2,067 2,963 1,809 2,638 1,870 2,525 2,548

Home Office Expenses 207 296 181 264 187 253 255

Project Contingency 376 562 322 492 330 467 467

Process Contingency 75 160 61 147 61 143 135

Total Overnight Cost (2011$M) 2,107 2,442 1,830 2,252 1,888 2,279 2,086

Total Overnight Cost (2011$/kW) 3,351 4,917 2,929 4,386 3,036 4,195 4,224

Owner's Costs 626 936 557 846 587 807 819

Total As-Spent Cost (2011$/kW) 3,820 5,605 3,339 5,000 3,461 4,782 4,815

COE ($/MWh) (excluding T&S) 107.0 152.6 99.8 141.9 102.6 135.4 138.7

Capital Costs 59.3 87.0 51.8 77.6 53.7 74.2 74.7

Fixed Costs 14.7 20.5 13.5 19.1 13.7 18.2 18.0

Variable Costs 9.3 13.0 9.2 12.8 9.4 12.2 12.2

Fuel Costs 23.8 32.1 25.2 32.3 25.7 30.7 33.8

COE ($/MWh) (including T&S) 107.0 162.4 99.8 151.8 102.6 144.7 148.9

CO2 T&S Costs 0.0 9.8 0.0 9.9 0.0 9.2 10.2

CO2 Captured Cost (excluding T&S), $/tonneB N/A 78.9 N/A 66.5 N/A 63.2 61.0

CO2 Avoided Cost (including T&S), $/tonneB N/A 118.7 N/A 102.9 N/A 91.7 99.3

AAll cases use high-risk financial assumptions consistent with NETL’s “QGESS: Cost Estimation 

Methodology for NETL Assessments of Power Plant Performance.” (2)

BBoth the costs of CO2 captured and avoided were calculated based on the non-capture supercritical 

pulverized coal (Case B12A) data provided in the “Cost and Performance Baseline for Fossil Energy 

Plants, Volume 1a: Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3” report. (3) Case 

B12A has a COE of $82.3/MWh, a CO2 emission rate of 1,618 lb/MWh-gross, a gross plant output of 

579,700 kW, and a net plant output of 550,012 kW.
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The following observations can be made regarding plant performance:

• In the non-carbon capture cases the dry fed Shell gasifier has the highest net plant 

efficiency (42.1 percent), followed by the two-stage E-GasTM slurry fed gasifier (39.7 

percent) and the single-stage slurry fed GEE gasifier (39.0 percent). The absolute values 

of the GEE and E-GasTM gasifiers are close to the reported values per the vendors. (16),

(51) The Shell efficiency is slightly lower than reported by the vendor in other 

presentations. (48)

• The energy penalty associated with adding CO2 capture is due to steam extraction for use 

in the SGS reaction, the auxiliary load for the CO2 separation and compression 

equipment, and a slight derate of the gas turbine due to the higher moisture content of the 

flue gas. The reduction in net plant efficiency ranges from 6 to 11 percentage points with 

the variability being due to the optimum gasifier designs (e.g., slurry vs. dry feed, syngas 

quench vs. syngas heat recovery) which may vary between the capture and non-capture 

plant configurations. 

• The lowest energy penalty (6 percentage points) corresponds to the GEE Radiant gasifier 

cases primarily due to the non-capture plant design (slurry feed, water quench) which 

results in a high moisture content in the syngas and thus a low addition of shift steam for 

SGS for the capture plant design. 

• The highest energy penalty (11 percentage points) corresponds to the Shell gasifier cases. 

The design uses a dry feed system and, in the non-capture configuration, has relatively 

high heat recovery in the syngas cooler with no water quench, resulting in very low 

moisture content in the syngas. For the capture configuration, a water quench is added 

which increases the moisture content of the syngas for the SGS reaction but decreases the 

heat recovery in the syngas cooler. 

• CB&I E-GasTM has the highest SO2 emissions (0.085 lb/MWh-gross) of the seven cases 

because refrigerated MDEA has the lowest H2S removal efficiency of the AGR 

technologies. 

The components of TOC and the overall TASC of the seven cases are shown in Exhibit 3-125. 
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-125 Plant capital cost for all cases

Source: NETL

The following TOC observations are made with the caveat that the differences between cases are 

less than the estimate accuracy (-15 percent/+30 percent). However, all cases are evaluated 

using a common set of technical and economic assumptions allowing meaningful comparisons 

among the cases:

• E-GasTM has the lowest TOC cost among the non-capture cases. The E-GasTM

technology has several features that lend it to being lower cost, such as:

o The firetube syngas cooler is much smaller and less expensive than a radiant 

section. E-GasTM can use a firetube boiler because the two-stage design 

reduces the gas temperature (slurry quench) into a range where a radiant 

cooler is not needed.

o The firetube syngas cooler sits next to the gasifier instead of above or below 

it, which reduces the height of the main gasifier structure. The E-GasTM

proprietary slag removal system – used instead of lock hoppers below the 

gasifier – also contributes to the lower structure height.

• The normalized TOC of the GEE Radiant gasifier case is approximately 4 percent greater 

than E-GasTM, and Shell is approximately 14 percent higher.
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• The GEE radiant gasifier (GEE quench is less than 1 percent greater than GEE radiant) is 

the low-cost technology in the CO2 capture cases with E-GasTM normalized TOC 

approximately 5 percent higher and Shell approximately 17 percent higher. 

• The ASU cost represents, on average, 12 percent of the TOC (range from 10-13 percent). 

The ASU cost includes oxygen and nitrogen compression, and in the non-capture cases, it 

also includes the cost of the CT extraction air heat exchanger. With nitrogen dilution 

used to the maximum extent possible, nitrogen compression costs are significant.

• The normalized TOC premium for adding CO2 capture averages 43 percent ($4,430/kW 

versus $3,105/kW).

The COE is shown for all seven cases in Exhibit 3-126. 

Exhibit 3-126 COE for all cases

Source: NETL

The following observations can be made:

• The COE is dominated by capital costs, and is at least 50 percent of the total in all cases.

• In the non-capture cases the E-GasTM gasifier has the lowest COE, but the differential 

with Shell is reduced (relative to the normalized TOC comparison) primarily because of 

the higher efficiency of the Shell gasifier. The Shell COE is 7 percent higher than EGasTM (compared to 14 percent higher normalized TOC). The GEE gasifier COE is 

about 3 percent higher than E-GasTM.

• In the capture cases the variation in COE is small; however, the order of the GEE and EGasTM gasifiers is reversed. The range is from $144.7/MWh for GEE Radiant to 

$162.4/MWh for Shell with GEE Quench and E-GasTM intermediate at $148.9/MWh and 
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$151.8/MWh, respectively. The COE CO2 capture premium averages 47 percent (range 

of 41 to 52 percent).

• The CO2 T&S COE component composes less than 7 percent of the total COE in all 

capture cases.

As presented in Section 2.6.4, the CO2 captured and avoided costs were calculated, and the 

results for the CO2 capture cases are shown in Exhibit 3-127. The cost of captured CO2

represents the minimum CO2 plant gate sales price that will incentivize carbon capture in lieu of 

a defined reference non-capture plant. The cost of CO2 avoided represents the minimum CO2

emissions price, when applied to both the capture and non-capture plant that will incentivize 

carbon capture in lieu of a defined reference non-capture plant. Both the costs of CO2 captured 

and avoided were calculated based on the non-capture supercritical pulverized coal (Case B12A) 

data provided in the “Cost and Performance Baseline for Fossil Energy Plants, Volume 1a: 

Bituminous Coal (PC) and Natural Gas to Electricity, Revision 3” report. (3) This case is 

representative of the lowest cost non-capture coal plant option. Case B12A has a COE of

$82.3/MWh, a CO2 emission rate of 1,618 lb/MWh-gross, a gross plant output of 579,700 kW, 

and a net plant output of 550,012 kW.

Exhibit 3-127 Cost of CO2 captured and avoided in all cases

Source: NETL

The cost of CO2 captured using SC PC as the non-capture reference case averages $67/tonne 

($61/ton) with a range of $61-$79/tonne ($55-$72/ton). The cost of CO2 avoided averages 

$103/tonne ($94/ton) with a range of $92-$119/tonne ($83-$108/ton).
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The normalized water withdrawal, process discharge, and water consumption are presented in 

Exhibit 3-128. 

Exhibit 3-128 Raw water withdrawal and consumption in all cases

Source: NETL

The following observations can be made:

• Raw water consumption for all cases is dominated by cooling tower makeup 

requirements, which account for 79-87 percent of raw water consumption in non-capture 

cases and 73-75 percent in CO2 capture cases.

• Normalized water consumption for the GEE non-capture case is 9 percent higher than the 

E-GasTM non-capture case and 13 percent higher than the Shell non-capture case 

primarily because of the large quench water requirement. 

• While both the normalized raw water consumption and withdrawal rates are 9 percent 

greater in the GEE Radiant non-capture case than in the E-GasTM case, the normalized 

raw water withdrawal and consumption rates are 6 percent and 4 percent greater, 

respectively, in the E-GasTM non-capture case than the Shell case. The discrepancy 

between withdrawal and consumption is because very little water is available to recover 

for internal recycle in the dry-fed Shell system

• The normalized raw water consumption for the four CO2 capture cases varies by 9

percent from the highest to the lowest. The variation between cases is small because each 

technology requires approximately the same amount of water in the syngas prior to the 

shift reactors. The difference in technologies is where and how the water is introduced. 

Much of the water is introduced in the quench sections of the GEE and Shell cases while 

steam is added in the E-GasTM case.
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3.5.1 Sensitivities

The effect of CF and coal price on COE is shown in Exhibit 3-129 and Exhibit 3-130, 

respectively. The assumption implicit in Exhibit 3-129 is that each gasifier technology can 

achieve a CF of up to 95 percent with no additional capital equipment cost. 

Exhibit 3-129 Capacity factor sensitivity of all cases

Source: NETL

The cost differential between technologies decreases as CF increases. At low CF the capital cost 

differential is more magnified and the spread between technologies increases slightly.
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Exhibit 3-130 Sensitivity of COE to coal price for all cases

Source: NETL

COE is relatively insensitive to fuel costs; a tripling of coal price from $1-$3/MMBtu results in 

an average COE increase of about 17-20 percent for all cases.

In the event that future legislation assigns a cost to carbon emissions, all of the technologies 

examined in this report will become more expensive. The technologies without carbon capture 

will be impacted to a larger extent than those with carbon capture.

The curves in Exhibit 3-131 represent the study design conditions (capacity factor) and fuel price

used; namely an 80 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for coal.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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Exhibit 3-131 Impact of carbon emissions price on study technologies

Source: NETL

The following conclusions can be drawn from the carbon emissions price graph:

• The impact of an increasing CO2 emission price has a significantly greater impact on 

the COE of the non-capture plants than the CO2 capture plants.

• At $60/tonne, the COEs of both the Shell and GEE Radiant cases without CO2

capture are nearly equal to the COE of the GEE Radiant case with CO2 capture.

Sale of the captured CO2 for utilization and storage in CO2 EOR has the potential to provide a 

revenue stream to the IGCC capture plant configurations. The plant gate CO2 sales price will 

ultimately depend on a number of factors including plant location and crude oil prices. The cost 

of CO2 captured represents the minimum CO2 plant gate sales price that will incentivize carbon 

capture in lieu of a defined reference non-capture plant. 

The curves in Exhibit 3-132 represent the study design conditions (capacity factor) and fuel price 

used; namely an 80 percent capacity factor and $2.78/GJ ($2.94/MMBtu) for coal.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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 Exhibit 3-132 Impact of carbon sales price on study technologies

Source: NETL

The following conclusions can be drawn from the carbon sales price graph:

• At $51.1/tonne, the COEs of the Shell CO2 capture and non-capture cases are equal.

• At $47.0/tonne, the COEs of the E-GasTM CO2 capture and non-capture cases are 

equal.

• At $39.1/tonne, the COEs of both the GEE Radiant and GEE Quench CO2 capture 

cases are equal to the GEE Radiant only non-capture case.
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

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4 Revision Control

The initial issue of this report was published in May 2007, and an updated revision was 

published in November 2010. Subsequent to the reissue date, updates have been made to various 

report sections. These modifications were made for clarification and aesthetic purposes as well 

as to bring all costs to 2011 year dollar basis.

Exhibit 4-1 contains information that was added, changed, or deleted in successive revisions.

Exhibit 4-1 Record of revisions

Revision 

Number

Revision 

Date Description of Change Comments

1 8/23/07

Added disclaimer to 

Executive Summary and 

Introduction

Disclaimer involves clarification on extent of 

participation of technology vendors.

Removed reference to cases 

7 and 8 in Exhibits ES-1 and 

1-1 since they no longer 

exist.

SNG cases moved to Volume 2 of this report as 

explained in the Executive Summary and Section 

1.

Added Section 2.8

Explains differences in IGCC TPC estimates in 

this report versus costs reported by other 

sources.

Added Exhibit ES-14

Mercury emissions are now shown in a separate 

exhibit from SO2, NOx, and PM because of the 

different y-axis scale.

Corrected PC and NGCC 

CO2 capture case water 

balances

The capture process cooling water requirement 

for the PC and NGCC CO2 capture cases was 

overstated and has been revised.

Replaced Exhibits ES-4, 3-

121, 4-52, and 5-30

The old water usage figures were in gpm 

(absolute) and in the new figures the water 

numbers are normalized by net plant output.

Updated Selexol process 

description

Text was added to Section 3.1.5 to describe how 

H2 slip was handled in the models.

Revised PC and NGCC CO2

capture case energy 

balances (Exhibits 4-21, 4-

42 and 5-21)

The earlier version of the energy balances 

improperly accounted for the capture process 

heat losses. The heat removed from the capture

process is rejected to the cooling tower.

Corrected Exhibit 4-13 and 

Exhibit 4-27.

Sensible heat for combustion air in the two NGCC 

cases was for only one of the two combustion 

turbines – corrected to account for both turbines

2 10/27/10

Updated circulating water 

flow rate values in Section 

3.1.8.

Revision 1 changes to capture system cooling 

water flow rate were not made in the text in 

Section 3.1.8 (Circulating Water System).

Added Supplemental 

Chapter 6 “Effect of Higher 

Natural Gas Prices and 

Dispatch-Based Capacity 

Factors”

N/A

Added Supplemental 

Chapter 7 “Dry and Parallel 

Cooling”

N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

258

Revision 

Number

Revision 

Date Description of Change Comments

Added Supplemental 

Chapter 8 “GEE IGCC in 

Quench-Only Configuration 

with CO2 Capture” 

N/A

Added Supplemental 

Chapter 9 “Sensitivity to 

MEA System Performance 

and Cost Bituminous 

Baseline Case B12BA”

N/A

Updated Aspen models

Major Aspen model updates included:

• Converting FORTRAN code-based steam 

cycles to Aspen blocks

• Using the Peng-Robinson property method in 

the Aspen gasifier section

• Modifying the AGR used in the IGCC cases 

to more closely represent commercially 

available technology

• Increasing the capture efficiency of the EGasTM plant with capture to achieve 90 

percent

• Correcting a steam condition error in the 

supercritical PC cases with capture

Updated case performance 

results

Major updates included:

• Revising the water balances to include 

withdrawal and consumption

• CAD-based HMB diagrams were replaced 

with Visio versions

Completed updating case 

economic results

Major updates included:

• Adding owner’s costs to the total plant costs 

to generate total overnight cost

• Updating fuel costs

• Revising the T&S methodology to include the 

July, 2007 Handy-Whitman Index, pore space 

acquisition costs, and liability costs

• Re-costing of cases based on the updated 

performance results

• Switching to COE as the primary cost metric 

(as opposed to levelized COE)

Updated report tables, 

figures, and text to reflect the 

revision 2 changes

N/A

2a 9/19/2013

Section 2.7.1 was revised to 

clarify the text that explains 

the level of technology 

maturity reflected in the plant 

level cost estimates.

N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

259

Revision 

Number

Revision 

Date Description of Change Comments

2b 7/13/2015

Volume 1 has been split into 

two sub volumes.

Major updates included:

• IGCC cases are reported in Volume 1b with a 

cost-only update (issued as an update to 

revision 2a)

• PC and NGCC cases are reported in Volume 

1a with a cost and performance update 

(issued as revision 3)

• Executive summary significantly revised and 

shortened

• Results analysis section added

Separated Supplemental 

Chapter 6 “Effect of Higher 

Natural Gas Prices and 

Dispatch-Based Capacity 

Factors” into a stand-alone 

report.

N/A

Separated Supplemental 

Chapter 7 “Impact of Dry and 

Parallel Cooling Systems on 

Cost and Performance of 

Fossil Fuel Power Plants” 

into a stand-alone report.

N/A

Incorporated the 

Supplemental Chapter 8 

“GEE IGCC in Quench-Only 

Configuration with CO2

Capture” into the body of the 

report.

The supplemental chapter was broken down and 

the information regarding the case describe within 

it is presented similar to cases B5A and B5B in 

Section 3.4.12. 

Removed Supplemental 

Chapter 9 “Sensitivity to 

MEA System Performance 

and Cost Bituminous 

Baseline Case 12A”

N/A

Updated the environmental 

targets to current limits 

published by the EPA and 

presented in Section 2.3

MATS and NSPS regulate SO2, NOx, Filterable 

PM, Hg, and HCl on a lb/MWh-gross basis.

Updated Section 2.4

covering Capacity Factors

Additional information has been included that 

supports the assumptions made regarding the 

capacity factors used for each technology type.

Removed portions of Section 

2.6 concerning cost 

estimating methodology

Many QGESS documents have been published 

that detail information generic to a number of 

studies published by NETL. In an effort to reduce 

the size of this report, text provided in these 

QGESS documents has been removed and 

references have been inserted that provide the 

QGESS document title and revision notation.

Added cost of CO2 Captured 

methodology and results.

The Cost of CO2 avoided methodology has been 

moved from the executive summary and 

combined with the Cost of CO2 Captured 

methodology in Section 2.6.4.

Removed Section 2.7 N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

260

Revision 

Number

Revision 

Date Description of Change Comments

Updated Section 3.1.4 to 

reflect the use of a dual 

carbon bed.

N/A

Updated Section 3.1.5

Superfluous information has been removed and 

the remaining information has been re-organized, 

especially concerning AGR/Gasifier pairings used 

in non-capture cases

Improved the BFD depiction 

of the HRSGs N/A

Updated all cases to a new 

case naming convention. Ex. Revision 2’s Case 1 is now Case B5A

Updated performance tables 

Major updates include:

• Table is split into two sections

o Performance summary

o Plant power and auxiliary load 

breakdown

o O2:Coal ratio

o Cold gas efficiency

o Combustion turbine efficiency

o Steam turbine efficiency and heat 

rate

o LHV basis efficiency and heat rate

Updated case performance 

results

Major updates included:

• Added particle concentration to emissions 

results

• Updated Energy Balance tables by adding 

Motor Losses and Design Allowances, NonCondenser cooling tower loads, and ambient 

losses

Completed updating case 

economic results

Major updates included:

• Updated to 2011 year dollars

• Revised the engineering and construction 

management costs

• Added NG supply line

• Updated the T&S costing methodology

• Updated fuel prices

Updated report tables, 

figures, and text to reflect the 

Revision 2b changes

N/A
Cost and Performance Baseline for Fossil Energy Plants Volume 1b: Revision 2b

261

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www.netl.doe.gov

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